西方石油 (OXY) 2016 Q4 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation's fourth-quarter 2016 earnings conference call. All participants will be in listen-only mode. (Operator Instructions). Please note this event is being recorded.

I would now like to turn the conference over to Chris Degner. Please go ahead.

Thank you Kate. Good morning, everyone, and thank you for participating in Occidental Petroleum's fourth-quarter 2016 conference call.

On the call with us today are Vicki Hollub, President and Chief Executive Officer; Jody Elliott, President of Domestic Oil and Gas; Sandy Lowe, Executive Vice President and Group Chairman Middle East; Ken Dillon, President of International Operations; Chris Stavros, Chief Financial Officer; and Rob Peterson, President of OxyChem. 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 the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the Company's most recent Form 10-K. Our fourth-quarter 2016 earnings press release, the Investor Relations supplement of schedules, our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off of our website at www.oxy.com.

I'll now turn the call over to Vicki Hollub. Vicki, please go ahead.

Thank you, Chris, and good morning everyone. Today, we will provide you a summary of our 2016 results, a high-level preview of 2017, and a more detailed update of our Permian inventory. But the key message I'd like to convey is that we will continue to provide value to our shareholders through an attractive dividend and an ability to grow our cash flow and earnings through moderate production growth while maintaining a strong balance sheet. This has been our strategy for a long time and it has not changed. What has changed is that we have dramatically derisked the delivery of that value proposition.

The quality of our portfolio today enables us to achieve our corporate goals through organic growth. Our exit from non-core areas along with proving up our Permian resources inventory provides us with a good blend of low decline and long-term cash flow generating assets that are important to support our dividends along with significant short cycle growth opportunities. We can now provide all of our targeted cash flow and earnings growth through organic development. In fact, Permian Resources can do it alone.

From 2013 to 2016, we have doubled Permian Resources' production. We can more than double it again over the next four years in a moderate commodity price environment. We can do this because we are a more geographically focused company today. This focus has led to technical and operational improvements in all of our core areas.

We have long been recognized as a global leader in enhanced recovery technology. As shown on Slides 6 through 8, with our more focused approach, we have built on our historical successes and are achieving even greater success today in our core international operations. A recent example is the Al Hosn Gas team, who increased the rated capacity of the gas plant to 110% of its original nameplate. We have now achieved the same level of success in our unconventional operations in the Permian.

In late 2013, we begin the transformation of our unconventional business, our restructuring into smaller strategic teams with greater emphasis on subsurface technical excellence and operational execution efficiency. This has paid off as we executed an aggressive appraisal program in 2014, followed by focused development plans in 2015 and 2016.

Our expanded subsurface expertise, along with our innovative drilling and completion practices, has resulted in step change improvements in our unconventional operations. We can now generate play-leading returns that are robust, even with lower oil prices. Jody will provide more detail on our Permian business.

As excited as we are about Permian Resources, the powerful combination of our long-term resource potential, our technical capability, and our partner relationship is even more compelling. The Permian, our Middle East countries, and Colombia all have one thing in common. They have significant remaining resource potential waiting to be unlocked by our technical expertise from primary to secondary to tertiary recovery.

Unlike some of our competition, we don't have to look elsewhere for opportunities, and we believe the Middle East and the Permian will continue to play a critical role in supplying the energy needed to meet the world's ever-increasing need. We are unique in providing this opportunity to investors.

In 2016, our oil and gas operations continued to lower total cost structure and increased recoveries from our reservoirs. You'll see the impact of this later in our reserves statistics.

Slides 10 through 12 show highlights of key 2016 accomplishments in all of our areas. I won't read them all, but would like to point out that we ended 2016 with $2.2 billion in cash and were able to achieve the higher end of our production guidance with less capital than expected. This is due to our capital execution efficiencies and is reflected in our F&D costs.

We replaced nearly 190% of our production at a cost of $9.65 per BOE. As a result, our total proved reserves increased from 2.2 billion BOEs to 2.4 billion BOEs, mostly due to Al Hosn and Permian Resources.

Al Hosn reserves increased due to better-than-expected reservoir performance. Increased reserves in Permian Resources were driven by a successful development program and higher well productivity.

Based on our Permian Resources current inventory of 11,650 wells, we will be able to continue to replace reserves for the foreseeable future. Our current proved reserves are limited only by the five-year SEC rule.

Last year's drilling program at Permian Resources delivered strong reserve replacement and F&D costs of less than $9.00 per BOE. When combined with our total cash cost of approximately $11 per BOE and incremental dollar invested in our Permian Resources business, delivers pretax margins in excess of 50% at a $55 WTI.

As we go into 2017, we have more confidence in the stability of the oil markets and increased flexibility in our capital plan as we have completed most of our multi-year investment programs. We are encouraged by the recent OPEC decision to lower production quotas, and we have seen the read-through in our operations and in increased demand for our crude in international markets. Our capital plan will prepare the business for an improved commodity price environment heading into 2018 while maintaining the flexibility to adjust activity if market conditions warrant. We will continue improving our operational and technical excellence to further reduce our cost structure and improve recoveries.

Based on our available cash and market conditions, we'll execute a capital plan of between $3 billion and $3.6 billion in 2017. In addition to cash flow from operations, our capital program will be supported by cash flow from a sizable tax refund and the monetization of non-core assets. We are reducing capital and Permian EOR and chemicals while holding capital flat in the Middle East and midstream. We'll increase capital moderately in Colombia and significantly in Permian Resources. Our plan anticipates oil prices to remain approximately as reflected in the futures market.

In the Permian Basin, the increase in capital spending will be mostly directed to increased activity in Southeast New Mexico and the greater Barilla Draw area. As I mentioned previously, the short-cycle nature of our development programs provides us the flexibility necessary in an uncertain market environment. If we see declines in oil prices, we will adjust our capital program down.

With increased spending in our oil and gas business, we expect production from our core assets to grow 4% to 7% in 2017, adjusted for production sharing contract effects. Most of the increase in production will be driven by Permian Resources.

In closing, I like to reiterate that our cash flow priorities have not changed. Our top priority for cash flow is and always will be the safety of our employees, contractors, and public, along with the maintenance of our operations.

The next priority is the support and growth of our dividends. Any remaining available cash will be used to fund growth opportunities primarily through organic growth in Permian Resources.

All of our decisions are driven by focus on returns and our strategy to continue to grow the dividend over the long term. As you know, this puts us in a unique position in the industry. We are more similar to majors with respect to our dividend, cash flow, and balance sheet objectives, but unlike majors, we have the greater growth potential because we have an incredible portfolio. To maximize the value of this unique position, we must be technically excellent and have a high level of operational efficiency. Focus will do this for us, allowing us to widen our competitive advantage. And we will continue to make deliberate decisions with respect to capital allocation. Keeping our capital allocation decisions consistent with our long-term strategy we believe will result in increased stock market value.

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

Thanks, Vicki, and good morning everyone.

Today I'll focus on the following items: a brief review of the fourth-quarter and full-year 2016 financial results; cash flow and liquidity items into 2017; and guidance for oil and gas production and specific business segments items for the first quarter and full year.

As Vicki noted, we ended last year with improved results in our core operations. We anticipate this momentum carrying into 2017 as a result of higher commodity prices, continued growth in our production volumes, and vigorous cost management. This is expected to lead to improved profitability and cash flow this year.

Fourth-quarter 2016 reported financial results for GAAP purposes were a loss of $0.36 per diluted share. Our fourth-quarter reported results included a non-cash accounting adjustment to book an allowance for doubtful accounts.

Our core financial results for the fourth quarter of 2016 were a loss of $97 million, or $0.13 per diluted share, compared to a loss of $112 million, or $0.15 a share, during the third quarter. Oil and gas pretax core income for the fourth quarter of 2016 was $2 million compared to losses of $49 million in the third quarter and $106 million during last year's fourth quarter.

For the fourth quarter of 2016, total Company oil and gas production volumes averaged 607,000 BOE per day, coming in at the high end of our guidance. Full-year 2016 production of 602,000 BOE per day from ongoing operations grew 7% and was better than expected due to stronger growth in Permian Resources and improved operations at Al Hosn Gas.

Permian Resources' production of 123,000 BOE per day during the fourth quarter improved sequentially due to our recent acquisition and increased drilling activity in the Delaware Basin. Resources production for the full year of 2016 grew 13% to 124,000 BOE per day despite a two-thirds reduction in year-over-year capital. These results were achieved due to a combination of better management around our base production and greater productivity from new wells.

Higher fourth-quarter volumes marks a turning point for Permian Resources as accelerated drilling activity and improved well performance is expected to lead to stronger growth in 2017.

Full-year 2016 cash operating costs in Permian Resources were $8.43 per BOE, a 25% improvement compared to full-year 2015 costs. Our overall Permian oil and gas operations generated more than $130 million of free cash flow after capital during the fourth quarter, a sequential quarterly improvement of over $100 million.

International production for the fourth quarter was 311,000 BOE per day, flat with the third quarter. Cash operating costs for our ongoing international oil and gas operations declined by 11% to approximately $10 per BOE for all of 2016.

Our international oil and gas operations from our core four countries generated more than $200 million of free cash flow during the fourth quarter.

Chemicals fourth-quarter 2016 pretax core earnings of $152 million increased from $117 million on a sequential quarterly basis, well above our guidance of $100 million for the quarter. Improvement in caustic soda prices was the single largest driver of higher profitability as firm global demand and reduced supply tightened markets. Higher vinyl margins driven by lower ethylene costs also boosted quarterly results. Our chemicals business generated roughly $140 million of free cash flow after capital during the fourth quarter.

Midstream pretax core results were a loss of $48 million in the fourth quarter of 2016 compared to a loss of $20 million in the third quarter. The lower sequential earnings reflected a decrease in equity income from our PAGP interest following their recent simplification, lower seasonal margins in our power and foreign pipeline assets, and mark-to-market impacts in our marketing business due to volatility in crude oil prices during the quarter.

Turning to our cash flows for the 12 months of 2016, we generated $3.6 billion of cash flow from continuing operations before working capital. Changes in working capital consumed $400 million of cash, most of which occurred during the first half of the year. Capital expenditures for 2016 were $2.9 billion, approximately half the year's outlay -- and below the prior year's outlay, and below our original budget of $3 billion.

Total oil and gas spending for the year was nearly $2 billion, a 55% decline compared to 2015. Despite the sharp drop in year-over-year capital spending, we managed to grow our production volume 7% during 2016.

Last year, we spent approximately $1.7 billion on asset acquisitions net of divestitures, primarily on oil and gas properties in the Permian Basin. We received $1.5 billion of net proceeds from debt issuance last year and have no material amount of debt maturities until 2021. We also received $880 million of cash from our settlement with Ecuador.

In November, the major rating agencies affirmed our single-A credit rating along with a stable outlook. We also returned $2.3 billion to our shareholders in the form of cash dividends.

For 2017, we have more than ample liquidity to execute our business plan. We started the year with $2.2 billion of cash, as Vicki mentioned, after selling $1 billion -- after generating $1 billion of cash from operations before working capital in the fourth quarter at WTI prices slightly under $50 a barrel. We anticipate oil prices rising moderately through the year and every $1.00 per barrel change in oil price impacts our cash flow by about $100 million annually.

Higher oil prices, together with growing production from Permian Resources, should improve free cash flow after capital by more than $500 million from our combined Permian operations. Better pricing as well as improved production and cost reductions at Al Hosn and in Oman should increase free cash flow from our international oil and gas operations by more than $400 million compared to last year. Improved crude oil marketing economics, better NGL pricing and the ramp-up of the Ingleside oil storage and export facility is expected to contribute approximately $150 million to $200 million of additional cash flow this year.

Free cash flow from our chemicals business is expected to increase by about $400 million in 2017 due to higher caustic soda prices, the startup of the joint venture ethylene cracker, and lower capital spending. The combination of a continued favorable global supply-demand balance and low inventories are expected to support further improvement in caustic soda prices in the market. Each $10 per ton increase in our realized price for caustic soda results in approximately $30 million of additional cash flow.

We expect to receive a cash tax refund in excess of $700 million sometime during the second quarter of this year. We also plan to monetize some non-core and nonstrategic assets, including our investment in the Plains General Partnership, which should generate proceeds of approximately $1.5 billion this year.

Beyond our immediate needs to fund our dividend and stated range of capital spending, excess cash would be reinvested in high-return opportunities and to accelerate growth, primarily in Permian Resources.

In terms of our capital spending, we adjusted our capital program last year in response to the sharp decline in product prices, especially during the first three quarters, with our full-year 2016 outlays of $2.9 billion at roughly half the prior year.

For 2017, our plan is to remain disciplined with our capital within the current product price environment. We will focus on allocating our capital where we have the highest return and opportunities for growth and we will harvest cash flow from assets for longer-term capital requirements that are largely complete.

As Vicki mentioned, we estimate our 2017 total capital program to be between $3 billion and $3.6 billion. The range of capital would depend on continued gradual improvement in market fundamentals and stability around product prices.

Our committed project capital is expected to decline by more than $1 billion from our 2014 outlays to an estimated $200 million this year. The reduction in capital for committed projects provides greater flexibility in our budget to pursue shorter-cycle growth opportunities.

With respect to guidance, and as Vicki mentioned, we expect our full-year 2017 production growth from ongoing operations to be in a range of 4% to 7%, between 625,000 to 645,000 BOE per day, slightly impacted by OPEC quota constraints, and volume impacts under our production sharing contracts due to higher oil prices. Our production growth expectations over the long term remain at 5% to 8%. Increased spending and drilling activity in Permian Resources is expected to provide production growth of 13% to 20% this year with total volumes in a range of between 140,000 and 150,000 BOE per day. Production in Permian Resources is anticipated to exit this year nearly 25% higher than year-end 2016 levels. Operational improvements at Al Hosn are expected to account for an additional 8,000 BOE per day of production this year compared to 2016.

For the first quarter, we expect our Company-wide production volumes to be in the range of 590,000 to 595,000 BOE per day. Seasonal maintenance turnarounds associated with gas related projects at Al Hosn and Dolphin are expected to reduce volumes by about 15,000 BOE per day in the quarter and are expected to return to full capacity for the remainder of the year.

Higher oil prices should generate -- should slightly reduce our Middle East volumes under our production sharing contracts, although better prices would also generate higher cash flow.

Production at Permian Resources is expected to be between 127,000 a day and 132,000 BOE per day in the first quarter.

In midstream, we expect the first quarter to generate a pretax loss of between $60 million and $70 million. The lower anticipated sequential result is mainly attributed to annual planned maintenance in our foreign pipeline business. We expect spreads between Midland and the Gulf Coast to be fairly consistent with the fourth quarter and anticipate receiving a slight uplift from our Ingleside crude terminal, which is now fully operational.

As 2017 progresses, we expect midstream earnings to gradually improve, generating positive income in the second half of the year. A large portion of the improvement should be driven by increased spreads between Midland and the Gulf Coast as a result of rising production in the Permian Basin.

In chemicals, we anticipate pretax earnings of about $150 million for the first quarter on continued strength in caustic soda prices, partly offset by higher energy and ethylene costs impacting our margins.

Construction of the Ingleside ethylene cracker is nearly complete, and we anticipate start up this quarter.

Our DD&A expense for oil and gas is expected to be about $15 per BOE for 2017 compared to $15.44 per BOE last year, partially as a result of lower finding and developing costs last year. The combined appreciation for the chemicals and midstream segments should be approximately $685 million.

Cash operating costs for the domestic oil and gas business should be about $13 per BOE during 2017 compared to $12.12 per BOE last year with much of the increase due to higher costs for purchased injectant and higher energy related costs.

Exploration expense for the full year is estimated to be about $100 million pretax with $25 million of the anticipated cost in the first quarter. Every $1.00 per barrel change in WTI affects our annual operating cash flow by about $100 million. A swing at $0.50 per 1 million BTUs in domestic natural gas prices affects annual operating cash flow by about $45 million.

Using current strip prices for oil and gas, we expect our full-year 2017 domestic tax rate to be about 36%. Our international tax rate should be about 55%.

I'll now turn the call over to Jody Elliott, who will provide more specific details around our 2017 plans for increased drilling activity in Permian Resources and a fresh update around our high-quality drilling inventory.

Thank you, Chris, and good morning everyone.

During 2016, we asked our teams to outperform many demanding operational and financial targets. Our teams rose to the occasion and exceeded our expectations during an extremely challenging time in our industry's history. Our team showed their resolved and ingenuity by staying focused on the priority needs of the business while developing new ideas and innovative technologies.

In particular, I'd like to acknowledge our field employees who maintain a safe and productive environment every day across our operational locations.

Our four main accomplishments in the Permian Basin during 2016 were continued reduction in our operating expenses, additional gains in drilling and completion efficiencies, further increases in the productivity of our wells, and continued improvement of our base production. During the two-year downturn, we reduced our operating expenses by over 27% on a per-BOE basis. We reduced our drilling and completion costs 33%. We decreased our F&D costs by 25% while realizing 10% compounded annual growth in our production.

We continue to build our improvements for long-term sustainability and believe we are positioned to continue this progress into 2017 and beyond. With over 2.5 million acres of diverse and growing opportunities, we believe we are uniquely positioned to be the long-term leader in the Permian Basin.

Today, we'd like to share more insight into our acreage position, our priorities and our key development areas. One of the highlights of our position and the focus of much of our development and growing inventories is our 650,000 net acres in the Delaware and Midland Basins. Permian Resources had another successful year of understanding our resource base and improving our development inventory value.

We increased the number of under $50 of WTI breakeven locations by approximately 1,250 wells while at the same time increasing the average lateral length of each well by 20% to 7,100 feet. These accomplishments, along with many more, give us the ability to drive double-digit growth from these assets for the foreseeable future.

Additionally, we will share an update from our Permian EOR business where our inventory of less than $6.00 BOE future development cost opportunities have now grown to over 870 million BOE. The resources and EOR assets and capabilities, along with our dominant acreage position in the greater Permian, set OXY up for a successful future.

And finally, as Vicki mentioned, we continue to stay focused on our capital-efficient, return-based development approach by seeking additional ways to maximize the net present value of the portfolio.

As we've communicated in the past, our entire Permian acreage position encompasses 2.5 million net acres with 1.4 million in our unconventional business area, and 1.1 million in our enhanced oil recovery business. Approximately 650,000 net acres of the 1.4 million lies within the Delaware and Midland Basin boundary lines, as indicated on the map on Slide 31. We consider these our core, unconventional acres. Of the 650,000 core unconventional acres, we have evaluated approximately 300,000 acres and have moved them into our development portfolio. The updated inventory count of 11,650 locations is associated with these 300,000 net acres. We will continue to evaluate the remaining 350,000 net core unconventional acres as we have a high degree of confidence in the potential and value of this acreage. Much of this acreage is already being appraised and will be part of a growing inventory over the next few years.

Our New Mexico Delaware Basin position encompasses 290,000 net acres and includes the greater Sand Dunes area, a key development position which I will speak to shortly. In the Texas Delaware Basin, we have 150,000 net acres, which includes 35,000 net acres from our recent acquisition in the Greater Barilla Draw, a development area which is now over 100,000 acres.

In the Midland Basin, OXY holds approximately 210,000 net conventional -- unconventional acres.

Other unconventional opportunities include 215,000 net acres in the Central Basin platform and 150,000 high potential net acres in the New Mexico Northwest shelf.

Finally, we continue to advance development potential across many areas, including 50,000 net acres within our emerging unconventional position and another 335,000 net acres are in the appraisal cube. We believe these opportunities can be exploited using our unconventional appraisal and disciplined development approach.

Turning to Slide 32, we have provided an update to the breakeven economics of our drilling locations associated with the 300,000 net development portfolio acres.

Before speaking to the year-over-year changes, I would like to reemphasize the average lateral length of the locations represented in the chart has increased from 5,950 feet to 7,100 feet. In total, we added 3,150 locations, an increase of 37%. Nearly half of our drilling inventory, or 5,300 locations, are economic under $70 WTI.

But what is most important in today's price environment is that our team nearly doubled our breakeven under $50 WTI inventory to 2,500 locations. Furthermore, we believe our inventory will continue to move towards a lower breakeven as we improve our efficiencies and increase our well productivity through continued subsurface evaluation, integration of 3D seismic, and data analytics.

Moving on to growth potential through disciplined capital efficient development on Slide 34, we illustrate our ability to accelerate growth through the end of the decade. Under a moderate scenario of a ramp to nine rigs by 2019, we conservatively believe we can drive a production CAGR of 20%. In an upside scenario with a ramp to 15 rigs by 2019, we conservatively believe we can drive a production CAGR of 30%. Our intention with this graph is to demonstrate the capabilities of these two core development-ready assets rather than indicating any particular future capital spend.

On the next slide, we'd like to highlight the two areas that will drive our growth at low breakevens for many years to come, the Greater Barilla Draw and the Greater Sand Dunes. We've spoken quite a bit about our industry-leading position in the Greater Barilla Draw. Equally as important is our position we've identified as the Greater Sand Dunes. We have four proven economic zones in this region and are delineating four other zones with a combined potential of over 2,000 wells. This is one of our most prolific positions in our portfolio and has continued to improve through several key value drivers I'll highlight on the next few slides. The majority of our $1 billion to $1.4 billion capital budget will be allocated to these two areas with approximately 80% in reserve adding capital investment. This will fund roughly six operated rigs and two equivalent nonoperated rigs during 2017. We expect to drill and complete 117 operated wells, which does not include the wells from our nonoperated investments. While we prioritize development to these positions in the short-term, we expect similar breakthroughs in other areas of our acreage position that will continue to improve through our subsurface characterization efforts and innovative technologies.

Turning to the next slide, we demonstrate how our wells have improved from prior performance and are also industry-leading in the area. In the top chart, our second Bone Springs six-month cumulative results have improved 150% from our old design in 2014 to our most recent wells in the second half of 2016. This was a result of improved wellbore placement through our subsurface characterization efforts and continued stimulation design improvements that include increased proppant loading from 1,000 to 2,100 pounds per foot and decreased cluster spacing from about 100 feet to about 50 feet.

On the bottom chart, our most recent well results continue to improve with average 30-day rates of 1,479 barrels of oil per day. On Slide 37, you'll see why we are so excited about this area of our portfolio. With 6,000 feet of gross interval and multiple zones enabling returns greater than 50%, we are developing this area to produce for many years to come. Our three most recent Cedar Canyon wells averaged a 30-day BOE per day rate of over 2,200 with 80% oil cuts, and similarly a recent well in the Wolfcamp XY IP'ed at a rate higher than 2,100 with a 71% oil cut.

As we look forward and continue our improvement in well costs, we continue to focus on all three areas for progress -- Design, operational performance, and managing our market or contractual costs. As we show with the New Mexico second Bone Spring well cost example, most of our cost performance gains have come through our efforts in operational performance. We see opportunities in both design and operational performance as we continue into 2017 and will be focused on reducing our drilling times, improving our execution of our evolving frac designs and continuing to use technological advancements like produced water fracs. Areas like New Mexico, where we will be entering into our manufacturing mode phase, will help us progress this quickly.

Further, as we move into a potential upward cycle of industry activity and cost inflation, we believe taking actions to sustain execution performance gains is the key. To support this, we are working with our service contractors to target areas and partnerships to allow us advantages with joint logistics and operational performance capabilities. We believe this proactive and collaborative work focused on overall supply chain and operational efficiency provides us the ability to sustain and even improve our well costs over the long-term.

Moving to our Permian EOR business, I'd like to highlight the vast inventory of low F&D projects that stress across the Permian Basin. Our industry-leading expertise in secondary and tertiary recovery, vast infrastructure, and secured CO2 sourcing provide us with a unique portfolio to maximize recoveries across our acreage position. We are currently recovering hydrocarbons from the Grayburg down to the Devonian and realizing recovery factors above 60% in some of our CO2 floods. The EOR assets have been the foundation for our Permian business and will continue to play a role in our portfolio as we invest in low F&D projects that provide significant cash flow for growth.

2016 was a great year for our EOR business. We made additional improvements in operating and capital efficiency while continuing to improve recoveries and maintain our base production.

At the end of 2015, we began Phase I of the CO2 flood in South Hobbs. We are extremely pleased with the response from the reservoir as results have been better than expected, and we are planning to impairment Phase II in 2017.

Our combined portfolio of unconventional and conventional acreage differentiates our position from that of our competitors. Our Permian Basin assets and our unconventional and EOR development capabilities and technology give us a unique perspective on creating long-term shareholder value. With over 40 years operating large field manufacturing-like CO2 operations, our workforce is skilled in managing diverse reservoirs for improved recoveries and value.

Our resources teams have continued to enhance our subsurface characterization, development capabilities, and technology as well. We believe the combination of these businesses and capabilities, in addition to our vast Permian acreage position, provides the ability to generate valuable growth opportunities for OXY. We are well-positioned to find new and innovative ways to increase ultimate recovery in areas with massive resource potential, but with low primary recoveries.

To close, we believe we've come a long way in leveraging the potential of the combination of unconventional and EOR businesses in our Permian position. The importance of running these two businesses together will grow even more over time. We also understand that having the resource matters little without pulling forward value in the near term. To achieve this, we will pursue opportunities to continue to increase net present value for our shareholders.

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

Thank you Jody. We will now open up the call for questions.

(Operator Instructions). Evan Calio, Morgan Stanley.

Good morning everybody and thanks a lot for the disclosure this morning. My question is your relative capital allocation in 2017, it's increasing for the Permian Resource up to the mid-30s% following these positive well results and inventory update. That appears to be a shift in the strategy towards the Permian. So how should we think about relative capital allocation within this growth bucket? Is the high end of your Permian guidance the first call in incremental capital above the dividend and maintenance, and would asset sales like those mentioned in Chris' opening comments, would that drive activity upside in 2017 on the strip, or how do you plan that?

First of all, going back to our cash flow priorities, when we are looking at the use of cash, the use of cash flow from operations, as I said in my script, we first allocate to our maintenance capital, our HES safety and sustainability capital. Then we fund the dividend. Beyond that, what we consider the growth capital, to allocate that, what we really look at is the combination of what it can provide for us in terms of returns, and also what it does for us in terms of long-term cash flow. So, when we make the allocation decisions, it's a combination of those two that we need to support our objectives and to continue to support the dividend. But within the portfolio now, in terms of what we see in the Permian resources business, that has been and will continue to be generally our highest return business. And we have this past year -- it was really a focus for us. We've said for a long time that the Permian Basin is pretty much the foundation of our Company, and so Permian Resources is the main growth engine. However, as you can see from the Slide 23, of our free cash flow swing in 2017, $400 million we're expecting to come from our international operations. Of that $400 million, about two-thirds of that will come from our Block 9 contract, which we re-signed last month. So the rest will come from Colombia and Al Hosn. So it's critically important for us to continue to work on growing our cash flow while at the same time ensuring that we invest as much as we can in the Permian Resources business, which for now for us is generating really good returns.

Maybe just a point of clarification. Does the asset sales that were mentioned earlier, do asset sales then drive upside to what you provided in the guidance today?

Today's guidance was based on the liquidity that we expect to have available to us for 2017. So, we don't expect any increase in our capital spend for 2017. We expect $3.6 billion to be the upper end.

We will go into 2018 with what we believe is a pretty strong cash balance, and will plan accordingly for increases in capital in 2018, should the market conditions warrant. But what we will look at is we will look at the prices for not only oil but in our chemicals business, and we will see what the market conditions look like.

Great. My second question, if I could, to go to the new updated inventory data, can you provide color on what -- I think you did in some of your prepared comments -- but color on what the 300,000 acres the location count is based upon represents? Meaning I just want to understand potential location upside from what's been analyzed, and understand better your cash priority statement that includes acquisitions, if that reflects a desire to add acreage in the Permian.

We'll let Jody answer the first part of that.

Good morning. The 300,000 acres, I think the way to think about that is it's really development-ready. We have been through that appraisal, subsurface evaluation, infrastructure investment kind of precursor to getting it to our development team. So, that's the 300,000. The difference between that and the 650,000 is that's now in the appraisal queue being worked. A lot of that is being derisked by competitor activity and our OBO activity. So, that's kind of the difference between the 300,000 and the 650,000.

With respect to the monetization of assets, we are continually looking at opportunities in our portfolio and prioritizing the projects that we have, and we will always do that. And there may be opportunities down the road where we may find things that would be better monetized today rather than waiting on development.

The issue in the Permian Basin is that, everywhere we look, we find, as we look deeper, we find more opportunities. So, the Permian is a place where we think that it's, first of all, very difficult to drill a dry hole there. Secondly, the more you learn about it and the more you engineer it, the better your wells get. And so we value that portfolio, but we are still very conscious of the fact that we need to optimize the net present value. So, we'll continually look at that. It's this process that we've gone through that's driven us to exit the non-core areas that we've exited in the last couple of years, and we will continue that process.

Great. I'll leave it there. Thank you.

Ed Westlake, Credit Suisse. (Operator Instructions). Roger Read, Wells Fargo.

Good morning. Thank you. I'll take Ed's question for him. Actually, if we could kind of go back to the discussion, Jody, at the end there, the 2,500 locations, and then I guess the discussion of the 650,000 acres. What should we think of as sort of the key items that get analyzed and changed such that you are able to double the number of locations and then think about -- and increase the number of below 50 breakeven locations going forward. What are the critical path items we should be paying attention to here?

Roger, for us, it's really probably two things. It's better execution efficiency. We are drilling more wells with the same number of rigs at a lower cost, so our time to market is faster. That changes your economics. The other is subsurface characterization combined with stimulation design. So we are landing our wells in places that we believe give us the highest stimulated rock volume. We are staying in zone at a much, much higher percentage through our drilling technologies. In our stimulation designs in general, you are seeing larger kind of per-sand volumes, tighter cluster spacing. But those are really custom-designed by each area. So that's really created a lot of the increase, as well as we continue to appraise and derisk new acreage. The 2,500 locations below 50, we think that's a pretty conservative number given that our approach to spacing we think about in that capital-efficient kind of return-based approach. We don't want over-capitalize these assets, so we look hard at what spacing ought to be. We evaluate that. We test different spacing scenarios and continue to look at scenarios, spacing scenarios, from our OBO exposure and learn from those as well.

Thanks. And then kind of along those lines, as we think about, on Slide 34, the nine-rig baseline of 20% CAGR and the higher rig count for 30%, does that require those 2,500 well sites going up, or is it an oil price-driven event? Or maybe another way of thinking about it, if all of these efficiencies come through maybe quicker than you think, do we get 15 rigs and a 30% CAGR even if crude stays, say, $50 to $55 where it's been here year-to-date?

There's plenty of inventory. That projection of the 20% and 30% CAGR is from those core development areas. So there's over 14 years of rig activity if you were at 10 rigs to drill up that inventory. So it's not an inventory question at all to drive those kind of growth rates. And the capital requirement for both the 20% and the 30% growth rates are pretty moderate.

So I guess then my final question is why not something, and maybe this goes more to Vicki, but why not something a little more aggressive here if the numbers work fairly well?

It goes back to being capital-efficient and return-focused. We want to make sure we have the subsurface understanding, our execution efficiency, our technology and the infrastructure all timed properly so that you get the best rate of returns. And then the amount of capital that gets allocated goes back to the priorities that Vicki mentioned earlier.

All right. I think I get that. Thank you.

Ed Westlake, Credit Suisse.

So, just on the international production and CapEx, I was thinking that CapEx would come down a bit this year. The $900 million still feels flat year-over-year. But maybe talk about how long you can keep sort of the international production flat or the growth outlook, say, out for the next few years and how much CapEx it would take to do so?

We have lots of opportunities in both, especially in Oman, where we just recently obtained some seismic over Block 9, so we are doing infill drilling that's very successful. We've got Block 62 gas development. We also see opportunities above and below our current steam flood interval in Mukhaizna, and so we have a lot of potential there, and that's why I mentioned it in my comments.

I think people don't realize that actually Oman and Qatar have stacked pay, not exactly as obvious to most of the industry as the Permian is, but they're stacked pay intervals, and we are having success developing outside of what our traditional and original completion intervals were. So, we are really excited about what the seismic is showing us.

We are also pretty excited about our cost cutting in Qatar where our team has been able to develop sort of a modular platform that will be able to enable us to expand what we are doing there at a much lower cost.

I'll pass it to Ken Dillon to talk a little bit more about those, but we have opportunities, both in Oman and Qatar, to continue to keep production flat or slightly grow.

Good morning. It's Ken here. As you can see from the slides, we increased the Al Hosn gas plant capacity by 10%. That was done by very detailed technical reviews, both by engineers and operational staff, and then controlled trials were done throughout the process before running the whole plant to capacity. That's an increase of capacity of 10% with virtually no capital at all.

If you look at Qatar and you look at the new jacket design there, we basically eliminated the lift barge. We've eliminated going to large fabricators in the region, so we've dramatically dropped drilling costs in Qatar, which opens up all sorts of opportunities there.

In terms of Block 9, as Vicki said, we, last month, signed the new Block 9 contract with his Excellency, the Oil Minister. That's a 15-year contract where we see substantial growth opportunities, both in oil and gas and in exploration. We think there are other opportunities in Oman that are a good fit long-term for us. So overall very positive.

Mukhaizna, you can see from the slide the growth trajectory that's possible with investment there. And we've also been trying to build on the Permian experience of assembly-line processes in drilling, rolling out OXY drilling dynamics around the world. We are making significant savings, significant reductions in time to market.

So, in terms of opportunities, our goal is to try and compete with Jody and also deliver long-term cash flow for the Corporation. In terms of how much capital you would need to keep it going, that's really a capital allocation point for Vicki I believe. But our goal is to continue to get better throughout international and continue to offer parameters to the Corporation.

Okay. And then on the theme of competing with Jody, on Slide 34 you've laid out a Permian growth trajectory at different rig counts. Maybe just a little bit of color on how you've risked the EORs or the well performance behind that, because, obviously, your first-half wells in the Sand Dune area were better than your -- third quarter was better than the first half, fourth quarter was better than the third quarter. Maybe just give a sense of how much of that improvement have you baked into that production forecast? Thank you.

That's a good question. I don't think we've baked a whole lot of that improvement in in the forward look, so I think there's upside potential. Our type curves represent the production from full-section development. Your first wells may be better than the last well on a section. So our type curves are based on the average and that forward look is based on the average. So throughout this year, just like we did last year, we expect continued improvement in both cost and well productivity. So, I think there's upside to that production plot, both from a pace standpoint, number of wells you drill per rig line, and productivity.

Thank you.

Asit Sen, CLSA

Thank you. Good morning. I have two questions. One, on Slide 14, Permian Resource gas margin looks like greater than $30 BOE. When compared with EOR, which has a low cash cost, it looks like the cash flow profile of OXY Permian as a whole has improved. So, Chris, could you frame for us at what price, given improvement, are we cash flow neutral? And in terms of cash flow overall Permian for OXY, what happens at a $60 or $70 oil?

At $60 or $70 oil, things change fairly significantly based on what -- the numbers we gave you on our sensitivity around oil prices obviously. But keep in mind that what we said was that there's a lot of flexibility in the capital program, as Vicki pointed out. We will sort of see how things go in terms of commodity prices through the year. Obviously, we would be more encouraged to maybe spend a little bit more money at the higher end of the range, better prices. So we will just sort of see how things go.

We gave you all sorts of points in terms of cash flow changes and deltas from the different business segments, so I think I have a high degree of confidence in your modeling ability, so you should probably be able to come to some sense of what's going on.

The Permian business as a whole, as I mentioned, generated quite a bit of free cash flow, and Permian EOR is sort of there largely to harvest the free cash flow to redeploy into Permian Resources.

So, on the cash neutrality, it could sort of be whatever you want it to be. We were under $50 WTI in the fourth quarter. We are spending -- so you're almost there now if you wanted to spend lower amounts of capital and to sort of keep production flat, but it's largely dependent on how much you would like to grow. And we think we have a lot of opportunities, as Jody pointed out, 11,650 places to park the money so -- at good returns. So I think that is the best way to frame it.

Okay. And then, given the new information, I'm just wondering your thoughts on balancing the opportunity to sell some Permian acreage that's not in your core development areas and potentially use the proceeds to accelerate development drilling. And I didn't hear on asset sales, South Texas gas assets. Has anything changed there?

As I said previously, we are continuing to look at our opportunities to monetize things where it makes sense, where we think that would increase the net present value for our shareholders. While we are not prepared to talk about specific assets today, we will continue that process. And as we make decisions, certainly we will share that with you, but it's something that we think about and evaluate pretty much on an ongoing basis.

Thanks. A follow-up for Jody please. Jody, average lateral length has gone up 20% to 7,100 feet. Could you talk about ability to drill longer lateral in this development mode? And could you remind us what percent of your permanent acreage, that sort of focus area, is operated versus nonoperated?

So, the operated versus nonoperated in that kind of core 300,000, you can kind of think 75% to 80% operating kind of position there.

With regard to the longer laterals, that's been a great effort by our business unit and our land organization to continue to core up, so doing swaps, doing trades, picking up pieces of acreage to drive that lateral length longer. So, I expect us to continue to do that. The majority of our wells will be longer laterals. That's just an average of the whole inventory. Technically, there's not a problem. 10,000 early on in horizontal development was a bit of a challenge. 10,000 is no longer a challenge. We are looking at even the option of 15,000 now.

Thank you.

Brian Singer, Goldman Sachs.

Thank you. Good morning. A couple of follow-up questions to what's been asked. First, with regards to the Permian, to clarify on the longer laterals, can you talk about what the lateral length is that you expect for the 2017 program as it regards to the 300,000 acres you're focused on?

And then with regards to 350,000 acres where you don't have identified locations, I think you mentioned in your prepared comments that you are delineating that. Can you talk more specifically about those plans and whether you see scale enhancing acquisitions as likely in that part of the Permian?

The bulk of the development this year will be 7,500 foot or 10,000 foot laterals. If we have to drill a 4,500 foot lateral, it's because we've already developed or started developing a section that way, and we really can't change. So most of our wells will be the longer version.

On the 350,000 acres we are delineating, it's really multiple things. We are drilling appraisal wells on our own acreage. We are evaluating 3D seismic. Again, those two equivalent nonoperated rigs really are six to eight actual rigs in any day of the year. So we get a lot of information from that nonoperated position that helps derisk, plus just watching what other competitors do offset of this acreage.

So, with regard to acquisition, it's going to be a function of what we think about that acreage, what the current position is, what trade opportunities there are to core up before you go down the acquisition path.

Got it. Thanks. And then going to the point on free cash flow, I just wanted to also get just a good clarification between Slides 23 and 17. We see on Slide 23 the $950 million to $1 billion incremental free cash flow you expect, and I think, in your prepared comments, you said you expect an incremental $500 million from the Permian, which I think was Resources and CO2. If you could maybe just verify if that was the case? So is that essentially the incremental free cash flow you expect overall in 2017?

And then more broadly, are you trying to reflect some greater comfort outstanding cash flow relative to the dividend, assuming the balance sheet doesn't go out of control, or is there still a more specific objective to try to stay within cash flow after dividend?

No, we provided the delta of the free cash flow that we expect in some of the pieces of the business based on prior investments that we've made that are now completed, so there's, to some extent, that, specifically around chemicals.

The Permian, a lot of that is driven by the production growth and the volume improvements that we've seen at good returns. And part of it obviously in oil and gas is some view around a little bit better price, but not much.

And going forward, I would tell you that not sort of -- we started the year with $2.2 billion of cash, and the capital program remains quite flexible, so we will sort of see how it goes as far as the spending. But again, the number one priority, as Vicki said, right after maintenance, is really to continue to be able to fund and grow the dividend over time based on our ability to grow volumes.

Great. Thank you.

Pavel Molchanov, Raymond James.

Thanks for taking the question guys. Like many companies, you've been finding ways to squeeze out costs from the CapEx budget, but since the original budget last November, of course we've seen escalation in US service costs, particularly pressure pumping, etc. So what is the underlying assumption in your new budget for service cost inflation, whether it's by geography or by segment?

So, we do believe there will be inflation pressure. And you mentioned pumping service. That's probably one of the areas where you will see it the strongest. But to counter that, we are really working two approaches. One is to continue to get better technically, some innovations that are happening in the drilling space and in the completion. We can drill our wells faster and better over time. That will help offset that inflation pressure.

But on the commercial side, we are working very closely with a group of suppliers to create the ability for them to have greater margins without just price increase -- more efficiency, better utilization, better logistics management. And so we think the combination of those two things can hold our overall well cost flat or continue to improve it.

Okay. And supposing that second-half commodity pricing ends up being better than the current strip suggests, would the incremental dollar go back to the buyback program that you kind of formerly had active, or would it go directly into the drill bit again?

We will have to see how conditions look in the second half of the year, but, currently, our plan would be not to increase our capital for this year but to go with the plan that we have in place and to look at what our program next year would look like. But it really is going to depend on how we feel about oil prices.

All right, appreciate it.

That concludes our question-and-answer session. I would like to turn the conference back over to Chris Degner for closing remarks.

Thank you, everyone, for participating today. Have a great day.

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