Occidental Petroleum Corporation (OXY) Q4 2017 Earnings Conference Call Transcript

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Occidental Petroleum Corporation (NYSE: OXY)Q4 2017 Earnings Conference CallFeb. 14, 2017, 11:00 a.m. ET

Contents:

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  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day everyone and welcome to the Occidental Petroleum Corporation's Fourth Quarter 2017 Earnings Conference Call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the * key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press * and then 1 using a touchtone telephone. To withdraw your questions, you may press * and 2. Please also note, today's event is being recorded. And at this time I'd like to turn the conference call over to Mr. Richard Jackson, VP of Investor Relations. Sir, please go ahead.

Richard Jackson -- Vice President of Investor Relations

Okay, thank you, Jamie. Good morning everyone and thank you for participating in Occidental Petroleum's Fourth Quarter 2017 Conference Call. On the call with us today are Vicki Hollub, President and Chief Executive Officer, Cedric Burgher, Senior Vice President and Chief Financial Officer, Jody Elliot, President of Domestic Oil and Gas, Ken Dillon, President of International Oil and Gas Operations, and B.J. Hebert, President of OxyChem.

In just a moment, I'll 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 10K. Our Fourth Quarter 2017 Earnings Press Release, the Investor Relations Supplemental Schedules and our non-GAAP to GAAP reconciliations, and the conference call presentation slides can be downloaded off our website at www.OXY.com.

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

Vicki Hollub -- President and Chief Executive Officer

Thank you Richard, and good morning everyone. Before I talk about our business results, I'd like to first thank our employees for their efforts to ensure a safe workplace for our employees, contractors, and the public. In 2017, we had the best employee and combined employee-contractor injury and illness rate that we've ever had. In addition, Oxy Oil and Gas had an industry-leading employee IIR, that's Illness and Injury Rate, of 0.11. This is a result of a long trend of improving safety performance, which indicates that safety is not an initiative for us, it's a part of who we are. It's embedded in our culture, which is a reflection of the quality and commitment of our employees. On behalf of the management team and our board, I want to thank our employees for owning safety.

Today I'll share some highlights from 2017, and then some key items we consider for disciplined reinvestment and what that means for allocating capital. I'll then conclude with details of our 2018 capital program. Cedric will update our progress on our Breakeven Plan.

In 2017, we focused on improving our cash flow through value-based growth and Permian Resources, enhancing our portfolio, increasing the value of our assets, and using technology to drive operational performance. We enhanced our portfolio by increasing cash flow from OxyChem in 2017 with a completion of the Ingleside Ethylene Cracker, which reached full capacity in 2017. OxyChem will provide additional incremental cash flow in 2018 from the 4CPe Plant that was commissioned and put on production in December of 2017. The plant, located in Geismar, Louisiana, uses an OxyChem patented process to produce 4CPe, which is a raw material used in making next-generation, climate-friendly refrigerates with low global-warming and zero Ozone depletion potential. The project was completed on-time and on budget, and it represents another significant accomplishment within our Breakeven Plan.

We increased the value of our assets through increased productivity, significant reserves replacement, optimum cash flow from our international operations, and increased exports from our Ingleside Crude Export Terminal. Our increased productivity came mostly from our Permian Resources business, where we achieved record initial production rates across eight benches and continued to deliver step-change well results in Greater Sand Dunes during the Fourth Quarter.

These results have helped drive our capital intensity down while adding to our long-term reserve potential. For two years in a row, we've achieved all-in reserve replacement ratios of nearly 190 percent companywide, with F and D costs of less than $10.00 per BOE. In Permian Resources, our reserve replacement ratio in 2017 was a record-setting 365 percent with an F and D of $9.77 per BOE. We provided additional details on our 2017 reserve data in the appendix and earnings release. We'll continue to focus on optimizing recoveries and F and D through our value-based development approach.

Equally important were similar improvements in our international businesses where we generated over $1 billion of free cash flow. And I want to take a moment to recognize our Oman team. We've operated in Oman for almost 35 years and recently achieved a significant milestone with the production of our 1 billionth barrel of oil. With the extension of Block-9 and the new contract in Block-30, we're excited about continuing our long history of success and partnership in Oman.

Lastly, I'd like to emphasize how advancing technologies have improved our operations. Our investment in sub-surface characterization has driven progress in both our unconventional EOR assets and our unconventional assets and we're increasingly finding more synergies between them. Four unconventional EOR technical pilots that we began in 2014 have increased our technical understanding of how these two assets will work together in the future and will provide significant option value across our large Permian position. This innovative work, in combination with our petrophysical advancements to improve primary recoveries, positions us to lead the industry in full-cycle value and return on capital employed.

We're also advancing our use and sequestration of anthropogenic, or man-made, CO2. One important step was our work with EPA to develop the first monitoring, reporting, and verification, or MRV plan for CO2 injected at our Denver Unit asset in 2016. Our MRV plan provides transparent and formal accounting for permanent geologic sequestration as a part of our EOR process. During 2017, we applied for and received approval for another MRV plan in our South Hobbs asset, the second ever issued by the EPA.

We reported volume sequestered at the Denver Unit in 2017 and will report our sequestration amounts for both assets in 2018. These two assets represent two of our 34 CO2 EOR floods in the Permian, and through our MRV plans will demonstrate the significant potential that exists in our assets to store CO2.

Another important advancement of CO2 sequestration through EOR occurred last week when Congress passed the Future Act. This legislation can help incentivize the development of new carbon capture projects making more anthropogenic CO2 available for sequestration and EOR operations, operations that have MRV plans. This policy, and technical advancements, combined with our significant CO2 EOR position and infrastructure could provide emerging opportunities for Oxy and the lower carbon future that we must all work to achieve.

We look forward to continuing to grow our leadership in this space. To complement our sub-surface advancements, our teams have also worked on innovative solutions to manage costs long-term. We continue to make progress on the recently developed technologies and operational differentiators that we introduced to you during 2017, such as SL2, our multi-lateral technology and our logistics and maintenance hub in South East New Mexico. This hub -- which will ramp up operations through the first half of 2018.

To summarize our key progress in 2017, we showed three key metrics on Slide 5. Enhancements to our portfolio enabled us to fund our dividend and sustaining capital with our cash flow from operations and to fund our growth capital with a combination of cash on hand, our tax refund, and proceeds from net asset sales. This advanced our plan to break even. The 20 percent improvement in the six-month cumulative production volumes we achieved in Permian Resources will significantly increase our resources value. This is a result of several years of excellent sub-surface work that is beginning to fully mature and be visible in our results.

Finally, our ability to replace our production at close to 190 percent replacement ratio with high-quality, low F and D production makes us very confident that this is sustainable for a long period of time and will deliver top-tier return on capital employed, and will provide more total returns to our shareholders.

Turning to Slide 6, our value proposition has not changed. When others chose to cut or eliminate their dividends, we developed a plan to continue and strengthen ours. We view our value proposition, which is founded on dividend growth, to be a commitment to our shareholders and not an option. We've been able to pursue this strategy consistently for many years as a result of the quality of our assets and the discipline of our management team. As you can see on Slide 30, over the past 16 years, we've given $30 billion back to our shareholders through dividends and share buybacks. Our scale, combined with the free cash flow generation of our international assets, Permian EOR and chemicals, along with the growth of our premium Permian Resources position, creates a truly unique value proposition in that we can provide strong dividends and meaningful growth, as well.

Our cash flow priorities also have not changed. Sustaining capital and dividends are non-discretionary items. Our first priority is to maintain an operational and environmentally safe business. Our second priority is to grow our dividend, as we've done for the past 15 years. As we look beyond our cash flow Breakeven Plan, we will consider several key factors for disciplined reinvestment that's for dividend and production growth long-term. Our investment decisions are focused on maximizing return on capital employed. We will not invest in projects unless they deliver a minimum return of 15 percent for domestic and 20 percent for international. The other factors we consider are, 1.) Pacing growth to maximize net present value, 2.) Improving low-cost inventory, 3.) Maintaining an industry-leading decline rate, 4.) Sustaining a secure capital structure for downside protection and upshot, upside opportunistic value creation through the inevitable commodity cycles, and 5.) Appraising long-term social and environmental opportunities to risk, like potential carbon pricing.

Now I'll update you on what this means for our next steps immediately beyond achieving our Breakeven Plan. As in on Slide 6, where we've illustrated what this looks like at various oil prices. Our first priority is to complete our Breakeven Plan and we expect to achieve this ahead of schedule. Our Breakeven Plan will secure our sustaining capital, current dividend, and 5 to 8 percent production growth at $50.00 WTI.

Beyond these milestones, we believe it's important to improve our dividend/payout ratio and reduce our net debt. This means that in the short-term, at $50.00 WTI, we'll grow the dividend at a nominal rate similar to last year, while investing in both short- and long-cycle projects to deliver 5 to 8 percent growth. Any additional cash flow will be retained to improve our net-debt metrics and be prepared for value-adding growth opportunities. We believe this conservative approach will further strengthen the sustainability of our dividend while giving us flexibility to remain opportunistic. Beyond these initial steps, we'll manage incremental dividend growth and reinvestment opportunities within the framework I've discussed.

At greater than $60.00 WTI, we're able to accelerate our payout ratio improvement and net-debt reduction and will weigh growing toward the higher end of our 5 to 8 percent range, and growing our dividend more meaningfully.

Turning to Slide 7, our capital program was designed to achieve our Breakeven Plan in the Third Quarter of this year. We expect this program will generate annual growth of 8 to 12 percent. Chemical spending has rolled off significantly, which will enhance free cash flow generation. In midstream, overall capital will increase modestly versus last year to accommodate an expansion of the Ingleside Crude Export Facility. We recently awarded EPC contracts to expand the capacity of the terminal by 2.5 times, up to 750,000 barrels per day. Total oil and gas capital spend will be approximately $3.3 billion. The international capital is primarily for sustaining purposes, as we complete our Breakeven Plan, but we expect higher investment in our international business in 2019 and beyond.

Similar to the international business, the Permian EOR business will spend capital to sustain current production levels. Permian Resources will receive a total of $1.9 billion in capital, of which $1.2 billion is for growth.

I'll now turn the call over to Cedric to review our progress toward the Breakeven Plan and our financial results.

Cedric Burgher -- Senior Vice President and Chief Financial Officer

Thank you, Vicki. I will begin with an update on our Breakeven Plan and then address financial results and 2018 guidance. On Slide 9, we have updated our progress toward our Breakeven Plan at low oil prices. As the chart shows, we have made substantial progress toward this goal and our business segments are exceeding targets. As noted in last night's press release, we have further accelerated our timeline and now expect to accomplish the plan by the third quarter of this year.

As most of you know, once we achieve our remaining milestones, we will have the cash flow necessary for our $40.00 oil price business sustainability case, or our $50.00 oil price business growth scenarios.

Slide 10 illustrates our progress toward the Breakeven Plan. In the chemical business, the 4CPe plant came online in December and will begin contributing toward the Breakeven Plan next quarter. In the mid-stream business, the Midland to Gulf Coast spread remained wider than our Breakeven Plan assumption of $2.10 per barrel, as it averaged $4.61 per barrel during the fourth quarter.

Ken Dillon will tell you about the Al Hosn Gas Plant de-bottlenecking that's beginning in the first quarter, and we have provided additional details on the capacity upgrade to our crude export terminal in the appendix.

In the Permian Resources business, we grew 20,000 BOEs per day, sequentially, leaving 50,000 BOEs per day to achieve our goal. Jody will give you additional guidance on the timing of new wells online and production. The chemical and EOR businesses are making operational gains and experiencing market improvements beyond our initial plan. Cost EXODA realizations, a key profitability driver for the chemicals business, improved further in the fourth quarter and solidified $150 million of market improvement show in the other improvements category of our slide.

In the EOR business, we have achieved the $5.00 per BOE of cost-savings we expected from the integration of the Seminole Saint Andrews CO2 unit into our network of floods. We have included a slide in our appendix highlighting this progress.

We are excited by the progress we have made and we will continue to communicate incremental progress toward our pathway to Breakeven.

My next slide illustrates our liquidity needs for 2018 and it has changed markedly in our favor since last quarter. We have adjusted the chart to reflect a commodity price of $50.00 WTI and our new capital budget of $3.9 billion. At $50.00 WTI, the cash required to attain our Breakeven Plan is more than covered by our cash balance. And at current prices, we would not need a cash flow deficit -- we would not run a cash flow deficit during 2018. At the end of the fourth quarter, we had $1.7 billion of cash and the Plains Units with a market value of approximately $600 million. In addition, we expect to evaluate and find opportunity to monetize non-core assets to maximize net present value of our portfolio.

Shifting to our quarterly financial and operational results on Slide 13, I'd like to start with our production results. Total reported and ongoing production was 621,000 BOEs per day. Permian Resources came in within guidance at 159,000 BOEs per day. Permian EOR increased by 2000 BOEs per day to 155,000, a result of a full quarter of acquisition volumes. International came in at 302,000 BOEs per day.

I'd like to take a moment to reconcile our fourth quarter production versus guidance. On the international side, our fourth quarter guidance was based on a Brent pricing assumption of $53.00 per barrel. Production-sharing contracts, or PSCs, had approximately a 5000 BOE per day impact on our production. Given that Brent averaged over $61.00 per barrel or an $8.00 increase versus our guidance assumption. While higher Brent prices are clearly a net positive overall, it does result in reduced production volumes for us.

On the domestic side, the Permian experienced third-party downtime of approximately 4000 BOEs per day, outside operator production timing of 2000 BOEs per day, and weather impacts of 1000 BOEs per day. The international and domestic items totaled approximately 12,000 BOEs per day, which reduced our production below our fourth quarter guidance. However, as Ken and Jody will detail, we are confident with our plan for 2018 and the execution fundamentals of our production growth continue to improve.

Earnings improved across all segments and our fourth quarter reported EPS was $0.65 and core EPS was $0.41. Reported earnings included about a $575 million benefit from the reevaluation of deferred taxes related to federal tax reform, which significantly decreased our fourth quarter effective tax rate.

Improvements in the oil and gas business segment were mainly attributed to higher oil and NGL prices. Realized oil prices increased 16 percent and NGL prices increased by 21 percent from the prior quarter. Operating flow before working capital improved sequentially to nearly $1.5 billion due to higher and NGL prices, along with higher Permian Resources production.

We spent $950 million on our oil and gas capital program during the fourth quarter. Total year oil and gas capital was $2.9 billion and we met our total capital budget of $3.6 billion. Chemical's fourth-quarter core earnings of $217 million came in above guidance, primarily as a result of higher realized cost EXODA pricing. Midstream fourth-quarter core earnings of $129 million also came in well above our guidance due to higher marketing margins from improved spreads and exports through our terminal.

With respect to 2018, we are affirming a capital budget of $3.9 billion which will generate 8 to 12 percent annual production growth. This equates to a total company production range of 640,000 to 665,000 BOEs per day. Our guidance assumes $60.00 WTI and $65.00 Brent for the first quarter and $55.00 WTI and $60.00 Brent for the remaining quarters.

The 2018 Permian Resources budget of $1.9 billion will drive a production range of 195,000 to 209,000 BOEs per day. The midpoint of this range equates to an annual production growth rate of more than 40 percent. Jody will provide additional color on our 2018 Permian Plan.

The 2018 international budget of $800 million will maintain a production range of 286,000 to 297,000 BOEs per day, which is sequentially lower due to the impact of higher oil prices on PSC contracts. Ken will provide additional details on the capacity expansion of the Al Hosn Gas Plant.

In the first quarter, we expect total production to range from 592,000 to 603,000 BOEs per day. Jody will give additional detail on the Permian Resources outlook. International production in the first quarter will be impacted by turnarounds at Al Hosn Gas and Dolphin. Al Hosn volumes are expected to average 58,000 to 59,000 BOEs per day during the first quarter and will ramp to 83,000 BOEs per day by the third quarter.

In midstream, we expect the first quarter to generate pre-tax income between breakeven $10 and $30 million assuming a midland to MEH spread of $3.00 to $3.25. The first quarter guidance also accounts for the turnarounds at Al Hosn and Dolphin. On a full year, we expect pre-tax income to range between $200 million and $300 million based on a Gulf Coast spread range of $2.50 to $3.00.

In chemicals, we anticipate first quarter pre-tax earnings of $250 million as the seasonality of sales for certain products improves in the first quarter. On a full year, we expect pre-tax income to approximate $1 billion assuming caustic soda prices remain at current levels. As a reminder, a $10.00 per ton move in caustic soda price equates to $30 million in pre-tax income.

Our DD&A expense for oil and gas is expected to be approximately $13.50 per BOE for 2018, compared to $14.87 last year, largely as a result of lower finding and development costs. Cash operating costs for the domestic oil and gas business are expected to average $12.50 during 2018, compared to $11.73 last year. Lower operating costs in the Permian Resources, which are expected to average under $7.00 per BOE are expected to be offset by higher costs in the Permian EOR business for oil price-sensitive purchased injectant and high energy-related costs.

And finally, on Slide 16, we have provided you with key cash flow sensitivities. I will now turn the call over to Jody.

Jody Elliot -- President of Domestic Oil and Gas

Thank you, Cedric and good morning everyone. 2017 was an incredible year for our domestic business. Our teams leveraged our sub-surface workflows and operating capability to drive improvements that de-risked our cash flow Breakeven Plan and added significant long-term value to our assets. We monetized non-strategic assets with three key results. First, we acquired the CO2 EOR Seminole Saint Andrews Unit to enhance our low decline Permian EOR business. Second, we invested additional capital into our Permian Resources strategic development plan. And third, we cored up a Midland Basin multi-bench area we are now developing.

We will continue to review our portfolio in 2018 and look for additional value-adding transactions. Our value-based development approach provided outstanding results across our business. Breakthroughs in geomechanics and petrophysical analysis of flow units drove an approximate 20 percent improvement in Permian Resources well productivity. Permian Resources lowered fourth-quarter operating costs to $7.63 per BOE, a 9 percent improvement from the fourth quarter of 2016. In Permian EOR, we've made significant progress at the recently acquired Seminole Saint Andrews Unit. In just one quarter, we increased production by 3600 gross BOE per day, produced op ex by over $5.00 per BOE, and reduced flaring by 60 percent. We've also improved the economics of future development by reducing drilling costs by over 30 percent, or $500,000 a well.

I also want to highlight our progress in advancing new technology. As Vicki mentioned, we've implemented four different, unconventional EOR pilots across the Midland and Delaware basins. The initial results are encouraging, and we believe that our position, scale, and over 40-year history of operating EOR projects provide OXY with an advantage that will be extremely difficult to replicate.

Progressing this technology will allow us to incorporate EOR into our future development plans and realize value with this upside option beyond just primary recovery. We are excited about these pilots and the future opportunity they represent.

Turning to Slide 19, the Permian Resources team added 750 locations to our less than $50.00 breakeven inventory in 2017, almost double the target set at the beginning of the year. This represents an additional four years of development at a ten-rig pace. The additional 325 locations added from lower cost and well performance are based on repeated improvements that are sustainable. Over 17,000 total net acre trades resulted in an additional 125 locations by enabling us to drill longer laterals and consolidate facilities.

We are extremely pleased with the progress made improving our inventory in 2017 and believe that our focus on value-based development and innovative technology will continue to grow our breakeven inventory in excess of our drilling pace.

On Slide 20, our Greater Sand Dunes Area delivered another quarter of play-leading results across multiple benches. In the fourth quarter, we brought online a total of 17 new development wells and one Avalon appraisal well. Our new wells in the fourth quarter had continued step-change productivity results as we had achieved in the third quarter. Our confidence continues to increase in 2018, as in January brought the Cedar Canyon 27 -- 28 Fed 44 H online that achieved a record 24-hour peak rate of 8361 BOE per day, and a 30-day rate of 6111 BOE per day.

As I mentioned in our last call, our understanding of localized production drivers across our position gives us confidence that we will continue to deliver high rate of return wells across the more than 2000 undeveloped locations in Greater Sand Dunes. In 2018, we will further integrate 3D seismic, data analytics, and deploy other emerging technologies for continued improvement.

Beyond Greater Sand Dunes, I also want to highlight a new six-section modular development area in New Mexico called Turkey Track. The Turkey Track 9-10 State 32 H in the Third Bone Spring has produced over 200 MBOE in 90 days and all five wells online in the fourth quarter are performing above expectations. We expect Turkey Track to deliver over a 40 percent all-in rate of return at $50.00 per barrel. While Turkey Track is only six sections, OXY has significant acreage in this region of northern New Mexico Delaware Basin. This modular development approach allows us to leverage scale across multiple smaller development positions. Innovative facilities design and development sequencing allows us to reduce costs for operations across several sections while using regional sub-surface characterization and operating efficiencies to leverage our basinwide scale advantages.

On Slide 21, I'll walk through Permian Resources Production for the fourth quarter and discuss the outlook for 2018. The continued improvements in well productivity and development optimization have put us ahead on our Breakeven Plan milestone. We now expect to achieve the 80,000 BOE per day of growth in the third quarter of 2018. We're extremely confident in our ability to execute this plan, as critical resources were secured in 2017.

Looking at the fourth quarter of 2017, good execution and well performance contributed to growing production by 20,000 BOE per day from the prior quarter and achieving a December exit rate of 172,000 BOE per day. However, during the fourth quarter, we incurred approximately 6000 BOE per day of downtime due to third-party pipeline and processing disruptions, OBO delays, and weather downtime.

In the first quarter, we changed our development plans to move a rig from Turkey Track, a two-well development area, to a Texas-Delaware four-well pad development area. This change was made based on the better than expected Third Bone Spring results in Turkey Track. So we can now pace this development differently to allow multi-bench development with the Second Bone Spring and ensure there is no additional cost incurred for facilities or trucking. This change reduces the number of wells online in the first quarter due to the larger pad activity, but is the right value-based decision and enhances our total-year production delivery.

First quarter production has been impacted by early January freezing weather by approximately 2000 BOE per day. But again, this does not change our strong outlook for the year. We've provided a quarterly production range for 2018 to help follow our progress as we're set to achieve approximately 45 percent production growth from 4Q 2017 to 4Q 2018.

On Slide 22 we provided details on our 2018 Permian Resource Capital Program. Consistent with our Cash Flow Breakeven Plan, our capital for the year is $1.9 billion. We will operate a total of 11 rigs and fund an additional two non-operated rigs. We plan to appraise at least six new benches across our development areas that will provide future growth opportunities. We will also start realizing the benefits of Aventine, our maintenance and logistics hub, which is now online with sand delivery and will be fully operational by the end of the second quarter. The partnerships created as part of Project Aventine will provide efficiencies and allow better margins for OXY and our partners. Our initial savings target per well from Project Aventine is between $500,000 to $750,000 per well, but we believe the full value implications are much higher as we expect improvement in time to market, last-mile, and well site logistics, safety, and future operating costs.

We will also continue progressing unconventional EOR pilots and implement new pilots in 2018, and we'll provide updates and share results as we can.

2017 was an incredible year and we're even more excited and confident about 2018. Thank you and I'll now turn the call over to Ken.

Ken Dillon -- President of International Oil and Gas Operations

Thanks, Jody and good morning, everyone. We had a strong year in the international business with our achievements summarized on Slide 24. The focus of the business during 2017 was two-fold. First priority was cash generation, which the upstream business delivered to the tune of over $1 billion in free cash flow. Second priority was continuing to develop a pipeline of potential projects in our core countries. This inventory is focused on strong returns for OXY and our partners. It builds upon our operational excellence in our core countries, including the use of the latest 3D seismic technology and drilling successes in Oman and Columbia.

Our major projects continue to be delivered on time and on budget, as shown on Slide 26. And we did all of this while achieving the best international ATS performance in OXY's history. There are a number of topics that I'd like to mention today. First is the de-bottlenecking of the Al Hosn Gas Plant, which will begin during the first quarter and be complete in the second quarter 2018.

Last year during our annual turnaround, we were able to optimize the gas plant for no additional capital. This contributed to the increase in production from 64,000 BOE per day in 2016 to 71,000 BOE per day in 2017. This year, during the turnaround, we de-bottleneck the plant for an additional 11 percent in production from fourth quarter '17 to third quarter '18 for only $10 million of capital. This de-bottlenecking will bring the cumulative expansion versus the original plant to approximately 30 percent, as shown on Slide 25.

Production during the first quarter will be approximately 59,000 BOE per day and we will achieve a peak rate of approximately 83,000 BOE per day in the third quarter. We're able to achieve this by utilizing a new patent-pending process to modify the inlets to the plant's absorbers.

Next, I'd like to talk about the continued consolidation of our position in northern Oman. We successfully renewed our Block-9 contract and we recently signed an exploration and production sharing contract for Block-30, which enhances our possession. We see opportunities for gas production in the area and synergies with our adjacent position in Block-62.

I'd like to highlight the performance of several projects in Columbia. In December, we reached a milestone of 45,000 barrels a day at the Lucera Enfantas Field. This was achieved just ahead of the 100th anniversary of the discovery well and we are excited about the continued development of the field. The Texas Steam Plot Pilot continues to exceed our expectations and a development project will be moving toward sanction this year. The project exceeds our international economic hurdle rates. Both of these projects are excellent examples of our organization's expertise in enhancing the recoveries of mature and complex fields.

Lastly, we've been successful with our step-out drilling programs in Oman and Columbia, which have added over 50 million barrels of net resource in the two countries. I'd like to thank the team for its disciplined work and commitment to safety. We're very pleased with how the business performed in 2017 and excited about the opportunities in our pipeline. I will now turn the call back to Vicki.

Vicki Hollub -- President and Chief Executive Officer

Thank you, Ken. I'd like to close by commenting on executive compensation since we've been engaging with the investment community on this topic. We have expanded the use of returns-based metrics for executive incentive compensation. The changes will impact both our short- and long-term incentives by incorporating cash return on capital employed as a key performance target with a short-term target of 18 percent and a long-term target of 20 percent. At our 2018 target compensation level, cash return on capital employed-based compensation will comprise about 20 percent of the total. This policy is consistent with our historical practices at OXY and improves alignment with our shareholders.

We'll now open it up for your questions.

Questions and Answers:

Operator

Ladies and gentlemen, at this time, we'll begin the question and answer session. To ask a question, you may press * and then 1 using a touchtone telephone. If you are using a speakerphone, we ask that you please pick up your handset before pressing the keys to ensure the best sound quality. To withdraw your question, you may press * and 2. Once again, that is * and then 1 to ask a question.

Our first question today comes from Roger Reid from Wells Fargo. Please go ahead with your question.

Roger Reid -- Wells Fargo -- Analyst

Yeah, thanks. Good morning. If we could go to Slide 4 to talk about well productivity improvement. And I was curious, is there a way that you could break that out at all between just changes in physical things, like, lateral length and the number of stages versus -- you've mentioned multiple times, and the improvement in well productivity -- how much of that is a design change or better rock, or you know, all the opportunities that are there?

Jody Elliot -- President of Domestic Oil and Gas

Roger, good morning. This is Jody. It's really a combination of both. If you look at lateral length in 2017, it's about a 10 percent in overall lateral length, but our productivity improvement is on the order of 20 percent. And you have to remember, this is based on a six-month cumulative. So a lot of the good wells that came online in the back half of the year aren't yet included in that improvement number. So it's a little bit of lateral length, but a lot about, again, how we land these wells, the flow unit work that we do to optimize where we place them, and then continued completion design changes to increase stimulated rock volume. But it's a combination of both, but more performance-driven than lateral length driven.

Roger Reid -- Wells Fargo -- Analyst

Alright, thanks. Could I get you to hazard a guess on continued improvement on productivity at all, or any sort of an internal target?

Jody Elliot -- President of Domestic Oil and Gas

I don't know if I can throw a number out. I mean, I get surprised every day with the improvements our teams continue to make. And I see some of the technology things we're working, whether it's in the execution side or on the completion side, and I still think there's more ahead. We've got some new frac designs coming out this quarter in Greater Sand Dunes and I think those are going to lead to even better rates.

And in addition to better rates, I think we're reducing our issues with offset frac hits and having to shut wells in because of doing frac work nearby. So not only are we trying to improve performance, we're trying to minimize the base production that's already online.

Roger Reid -- Wells Fargo -- Analyst

Okay, kind of, getting rid of the parent-child issues we've seen elsewhere, then.

Jody Elliot -- President of Domestic Oil and Gas

Exactly.

Roger Reid -- Wells Fargo -- Analyst

Okay, and then maybe just changing direction with my follow-up, I don't know for you, Vicki, or for Cedric -- with the company now certainly line of sight to the breakeven at $50.00, or effectively there at current prices, how do you think about the dividend or share repurchases as the company moves out of '18 and into '19. What's the preferred method for shareholder returns here?

Vicki Hollub -- President and Chief Executive Officer

Well, we prefer dividends because the dividends are given directly to the shareholders. And it's often hard to predict the impact of share repurchases. But you know, we have done a lot of share repurchases over time, as we showed you in the graph. But the way we, kind of, look at it is, we do it when we think it makes the most sense and adds the most value. And we, sort of, do that calculation by looking at the value of the chemical and midstream businesses and taking that from the total value of the company, but including debt and cash levels. And then you divide that by your total crude reserves. Then when you compare that to your finding and development cost for the projects that you're in. And in that scenario, we would go today investing more in the projects that we're doing.

So with that said, in those scenarios where we have incremental cash and we don't want to accelerate our pace of development because that would potentially destroy value, in those scenarios, assuming our stock is a little bit lower than normal, those would be scenarios that we buy shares back into the company. And you know, you've seen us do that. So that would be something that we certainly would consider doing.

We never want to talk about it in advance because we don't want to let others know that we're doing it. We want to make sure that we eliminate the potential of others buying our stock as we've talked about buying it back. So we think this approach, as we consider that, limits our natural bias to think that the stock's always undervalued, and it makes the calculation pretty straightforward.

Roger Reid -- Wells Fargo -- Analyst

Alright. I appreciate that. Thank you.

Operator

Our next question comes from Brian Singer form Goldman Sachs. Please go ahead with your question.

Brian Singer -- Goldman Sachs -- Analyst

Thank you, good morning.

Vicki Hollub -- President and Chief Executive Officer

Good morning.

Brian Singer -- Goldman Sachs -- Analyst

As we think about the path to achieving that $50.00 breakeven, I wanted to just focus a bit more on -- [00:45:38] to reduce well costs in the Delaware, in particular, which I think you have on Slide 53. Based on your contracts, how exposed are you to market inflation risk relative to what you have in the slide? And can you also talk a little bit more about the drivers of the design and efficiency improvements and the risk there to the upside and the downside?

Jody Elliot -- President of Domestic Oil and Gas

Hi Brian, this is Jody. The Slide 53 is one example of a well type in New Mexico. It's a Second Bone Spring 10,000-foot well. It's a three-string design, assumes 2000 pounds per foot in the completion, includes everything, its hookup, flow-back, first artificial lift, capitalized overhead. So it's an all-in capital cost. We see pressure on inflation, obviously. It's probably in the 5 percent range in the drilling area and more like 10 to 15 percent in the completion space. But with securing our resources in 2017 with separating sand from pumping service, and now with the start-up of Aventine in 2018, we see our ability to offset and even drive down costs in an inflationary period.

This is something we started a couple of years ago when we looked back at what really drove our improvements back then. And anticipating an inflationary cycle, what would we do different? So we focused on maintaining time to market, securing supply, securing resources, working the things that drive time to market because they're a much bigger part of the equation than just unit cost. And I can talk for a long time about Aventine, but there's a lot of things in place, not just sand delivery, but oil country tubular goods on rail instead of truck, the OxyChem hydrochloric acid facility, our work with Schlumberger there, a new sand delivery system for the last-mile logistics that will drive down trucking and reduce the number of people required on location.

So I'm just naming off a few. There's a long list of things that we believe continue to improve the cost structure, the capital intensity of our work in the unconventional business.

Brian Singer -- Goldman Sachs -- Analyst

Thanks. And I know this is just one example, but are well cost reductions of this type of magnitude baked into the $1.9 billion capital budget for Permian Resources or would achievement lead to lower capital needs relative to that?

Jody Elliot -- President of Domestic Oil and Gas

Yeah, we've baked in, kind of, flat from where we are today. So I think there's upside opportunity as we work through this next generation of technology. So some of those are in there, in our flat assumption. But we're just getting started with Aventine.

Brian Singer -- Goldman Sachs -- Analyst

Thanks. And then can you talk a little bit more about the six new benches you're planning to appraise in the Permian in 2018 and how the acreage you plan to evaluate compares to the new acreage that I think you said added 150 locations in 2017?

Jody Elliot -- President of Domestic Oil and Gas

Yeah, it's First Bone Spring Avalon, Second Bone Spring Lower in New Mexico, Second Bone, Third Bone, Wolf Camp C in Greater Barilla Draw. Greater Barilla Draw is 50,000 net acres, so success in those other benches really gives you a lot of scale to work with.

Brian Singer -- Goldman Sachs -- Analyst

Great, thank you.

Operator

Our next question comes from Phil Gresh from JP Morgan.

Vicki Hollub -- President and Chief Executive Officer

Phil, could you hold just a second? We did have another comment from Ken, international.

Ken Dillon -- President of International Oil and Gas Operations

Yeah, just to follow on from Jody on the international side, same drivers for us internationally, market forces and OXY in-house technology. We still see deflation continuing in drilling and completion arena at the moment, mainly because of the discipline of the NOCs and IOCs in this market, but also the entry of some new competition in the various product lines. Drilled our OXY drilling dynamics 3.0 at the start of 2018, we're making modifications to our drilling rig fleets and hardware, software, and data analytics.

If you look year-on-year in Oman North and in Columbia, we've reduced costs in Oman North by 12 percent and 26 percent in Columbia in these product lines. And if you look over the last three years for ourselves and our partners, we've saved over $420 million in the drilling and completion side, and we're hoping that that will continue this year.

Vicki Hollub -- President and Chief Executive Officer

Okay, Phil. Good morning.

Phil Gresh -- JP Morgan -- Analyst

Good morning. Yeah, first question coming back to capital spending. This year, you're at $3.9 billion, which is toward the upper end of the range you had talked about previously of the $3.6 to $3.9. Obviously, there is accelerating production growth that comes with that. But I guess I'm kind of wondering as we look ahead, Vicki, you've talked about a commitment to have a meaningful step down in cap ex in 2019 on the back of hitting the breakeven. So just want to get your latest thoughts on that. And you talked a bit about the various trade-offs in your opening remarks, but is there a specific commitment you're thinking about or a roll-off of infrastructure spending or anything that will be driving cap ex materially lower next year?

Vicki Hollub -- President and Chief Executive Officer

Well, once we get to the Breakeven Plan, we're still going to go back to our original 5 to 8 percent growth. We're forecasting 8 to 12 percent this year, but next year in 2019, we'll target the 5 to 8 percent growth. And targeting that growth with our dividend means that we'll certainly be able to reduce our cap ex below where it is today and back more toward the $3.4 to $3.45 range.

Phil Gresh -- JP Morgan -- Analyst

Okay, got it.

Cedric Burgher -- Senior Vice President and Chief Financial Officer

Phil, this is Cedric. I would just add, as I said in my prepared remarks, once we complete the plan, we will be able to live within cash flow, including -- and cover the dividend, even as low as $40.00. And so part of the answer to your question depends on what the commodity price environment will be going into '19. But we will have that ability even at low commodity prices to sustain our base and the dividend, all within cash flow.

Phil Gresh -- JP Morgan -- Analyst

And if I could just ask, maybe, a clarification before my second question. There was a comment about higher international spend in 2019 and I heard some of the prepared remarks there, but what's the order of magnitude that would be baked into the $3.4 to $3.45?

Vicki Hollub -- President and Chief Executive Officer

So it wouldn't be significant because what we have in Oman and some of the international operations are these shorter cycled projects that actually could -- we can vary that. We can almost vary it like we do the Permian, in terms of picking up rigs and activity levels. Ken, did you have an additional comment on that?

Ken Dillon -- President of International Oil and Gas Operations

Yeah, part of our focus this year is picking up on the exploration wells and step-out wells that we did last year. We've added 50 million barrels of net resource. Our goal is to hook all of these up this year, get them online. So some of the capital in Columbia will go toward that.

Phil Gresh -- JP Morgan -- Analyst

Okay, got it. And then so my second question is around the op ex for the US, the guidance of $12.50 a barrel is a little bit higher than my model, not hugely so, but given this incremental -- the resources -- barrels are coming on, I think, at $2.00-$3.00 per barrel that you've talked about in the past. And I think 4Q ended sub-$8.00 a barrel. So I'm just trying to understand, maybe, some of the moving pieces there and if you have any color about where the EOR cost is, given the higher oil price, etc.?

Jody Elliot -- President of Domestic Oil and Gas

Yeah, Phil, it's Jody. So in resources, we exited fourth quarter with op ex of $7.63. We expect operating expense in 2018 to be below $7.00, more like $6.75. We'll exit '18 below $6.00 so that additional production growth will continue to drive down resources op ex. On the EOR side, there's two components. The fundamental -- the things we control on rig work, and those kind of things, is pretty flat. The two things that move with oil price, one is there's some CO2 contracts that are indexed to oil price, or part of the contract is indexed to oil price. So as oil price goes up, the cost of CO2 goes up. The other is, we're injecting about almost 3 percent more CO2 this year, in 2018, than we will in 2017. As you know, we've started a new flood and we've expanded several others, and so that's consuming the CO2 on the front end. And obviously, the production comes as you go through the lifecycle of those projects.

Phil Gresh -- JP Morgan -- Analyst

Got it. So EOR is closer to $20.00 then, per barrel?

Jody Elliot -- President of Domestic Oil and Gas

Yeah, I don't have the number right here in front of me, but we'll get it to you.

Phil Gresh -- JP Morgan -- Analyst

Okay, thanks a lot.

Operator

Our next question comes from John Herland, from Societe Generale. Please go ahead with your question.

John Herland -- Societe Generale -- Analyst

Yeah, hi, thanks. Most everything's been covered. I was just curious about the EOR activity in Permian Resources, what you're expecting to get out of the wells by pursuing that. And then the other one is on the Aventine Venture. Will this be your only joint venture? Like, Schlumberger mentioned the joint venture on their call with you or working with you. I was wondering, are you going to do more of these corporate things to help manage costs in the future? That's it.

Unidentified Company Officer

Sure, I'd be glad to talk about both. So the EOR work in the unconventional space, when you look at primary production, you're recovering 8 -- 10 percent of the production. So there's a tremendous resource there. So the objective or the challenge is how can we increase that materially and do it economically? And so with either CO2 injection or miscible gas injection, both in the lab and in the trials in the fields, we've demonstrated we can recover incremental oil, and it doesn't behave like the traditional, conventional CO2 flood where you inject, and you push oil to the producers, and it's a long-cycle project. The oil recovery is actually quite quick. So it has a short-cycle nature to it.

So the objective is to continue to do pilots and understand how we take it from pilot to full-scale, and then how that affects development plans in the unconventional space going forward.

John Herland -- Societe Generale -- Analyst

So is this fracture or matrix veracity you're talking about?

Unidentified Company Officer

Your matrix permeability is micro -- it's not matrix. It's a function of the unconventional geology and whether you're in a sandstone or whether you're in a shale. So the behavior is different. That's all part of the learning that we'll talk about more as we're ready to disclose more of the details.

John Herland -- Societe Generale -- Analyst

Great.

Unidentified Company Officer

With regard to Aventine, Aventine is multiple companies at that site. So Aventine is set up to support Greater New Mexico, all the way from Turkey Track, and then our Greater Sand Dunes area. And so it's pumping service, it's oil country tubular goods, it's sand trans-load, sand delivery. It's a new sand last-mile logistics system called Sand Storm. It's an OxyChem HCL facility. And that's just where we're starting. Drilling tool -- with Schlumberger it's frac, it's drilling tools, it's cementing, and it's providing logistics improvements by the location.

In the Texas Delaware -- so you treat each area based on what the current infrastructure is. In the Texas Delaware, it's really more about securing trans-load and so we don't have the full-scale buildout of an Aventine-like facility, but we have trans-load secured. It's closer to the regional sands in Texas. Our sand provider has a regional sand mine that will be opening shortly, and so we'll take advantage of that in the Texas Delaware. And in the Midland Basin, really, the infrastructure is pretty good. It's just really securing supply of sand.

To give you just a couple of stats on the New Mexico impact, you think about the proximity of that to the well sites. It's a 60 percent reduction in the number of miles driven. You go from almost 20 million miles to 8 million miles. And then when you put in the new Sand Storm system that we're starting up this year, we can haul 27 tons of sand per load versus 22. You do that math, that drives another 1.3 million miles out of the equation. So it's 33,000 fewer truckloads over a five-year period. It also reduces 9000 metric tons of CO2. You think about accident statistics. It'll improve our safety. And then the new Sand Storm system that's really the last-mile part of this reduces the number of people required on site because of the automated nature of the way it works.

So that Sand Storm technology would apply both in New Mexico, Texas Delaware, and Midland. And then the logistics hub design and complexity varies as you move across those three areas, as well.

John Herland -- Societe Generale -- Analyst

Great, thank you.

Operator

Our next question comes from Pavel Molchanov from Raymond James. Please go ahead with your question.

Pavel Molchanov -- Raymond James -- Analyst

Thanks for taking the question. I know you don't generally give guidance by oil versus gas, but as we think about Permian Resources up 40-plus percent this year, is it going to be a broadly parallel increase between liquids and gas? So in other words, the gas/oil ratio, is it going to remain broadly stable throughout the year?

Jody Elliot -- President of Domestic Oil and Gas

Yep, Pavel, this is Jody. In 2017, our oil caps were, kind of, on the 60 percent -- right around 60 percent, and it actually increases a little bit 61 percent for a total of 2018. So your mix stays about the same.

Pavel Molchanov -- Raymond James -- Analyst

Okay, helpful. And then a quick one on Columbia. We've seen a lot of headlines, January, in particular, about pipeline attacks affecting a number of the major fields in Columbia. To what extent is your Q1 international guidance affected by that?

Ken Dillon -- President of International Oil and Gas Operations

I think the best way to answer is to look at our production last year. Since Q1 2017, our productions remain steady quarter by quarter. That's thanks to a lot of work in the field and excellent collaboration with our partner AcuDrill and the full support of the Columbian government. And we're planning to continue with the same approaches in 2018.

Pavel Molchanov -- Raymond James -- Analyst

Okay. But I guess, how many BOE a day have you lost year-to-date, for example, in Columbia, if you can share that?

Ken Dillon -- President of International Oil and Gas Operations

I think it's basically a variation on the answer I gave a moment ago. Our production from our areas is, basically, steady at the moment, and it's mainly as a result of the work that we've done with the government and with AcuPatrol. We're not seeing major impacts on our fields at the moment.

Pavel Molchanov -- Raymond James -- Analyst

Okay, fair enough. Appreciate it.

Operator

Our next question comes from Leo Mariani from NatAlliance Securities. Please go ahead with your question.

Leo Mariani -- NatAlliance Securities -- Analyst

Hey, guys. I was hoping you could talk a little bit about the way you're, sort of, splitting up capital in the Permian Resources division this year. Really between just Midland and Delaware. I don't know if I had this right, but I think I was seeing, maybe, roughly one rig in the Midland and ten in the Delaware. Is that something that you're going to sustain this year? Or is that going to move around? Can you just, kind of, talk about that broadly in terms of how you're thinking about Permian Resources capital over the next couple years with those two sub-basins.

Unidentified Company Officer

Yeah, you can kind of look at it two different ways. You can look at wells online. You can look at rig count. If you look at wells online, it's about 55 percent in New Mexico, 30 percent in the Texas Delaware, and about 15 percent of the wells in Midland. And that probably stays fairly consistent throughout the next couple of years. We're running 11 rigs operated. Again, that's about six in New Mexico, four in Texas Delaware, and a rig or two in the Midlands. So I don't see that changing drastically. But again, we're continuing to develop inventory, learn new things. Turkey Track's a great example. We thought we had a single bench Second Bone Spring Development there. Turns out we've got two. So as we learn more and we change how we think about our inventory, obviously, that could adjust.

And I want to go back to Phil's question. He asked about op ex and EOR. It's about $19.00 a barrel.

Leo Mariani -- NatAlliance Securities -- Analyst

Alright, and then, maybe, could you talk a little bit about plans for Oman Block 30? I think you guys recently signed that late last year? Are you starting to see incremental capital there in the budget in 2018? When can we start to see some incremental production? Is it going to be largely oil targets? I think you guys had mentioned gas potential, as well, in Oman. So what can you say about that as it develops over time?

Ken Dillon -- President of International Oil and Gas Operations

Yeah, I think as you can see from the map on Slide 24, Block 30 fits perfectly into the Oman North jigsaw. There's currently three discovery wells on the block and two reservoirs that we are completely familiar with due to the work on the other blocks. We have the same approach internationally as we have domestically. The goal is value, not just driving up production. So the short-term plans are basically to reprose the existing seismic on the block, come up with a development plan and start drilling, probably toward the end of this year and have some production next year. So relatively small amounts of capital invested this year, mainly study work and coming up with a value-based development plan.

Leo Mariani -- NatAlliance Securities -- Analyst

Alright, that's really helpful. And last thing you mentioned, portfolio management, you know, $0.5 billion to $2 billion. I guess it's kind of an ongoing thing for your guys. Do you see anything on the horizon here in 2018 where you might look to sell-down any of your assets? Or is that just something that's out there and might take several years?

Vicki Hollub -- President and Chief Executive Officer

Well, certainly for our core assets, we're satisfied with where we are. The only thing that we're continuing to do is look for things, assets that are way out in the inventory and the Permian. So things that we can't get to anytime soon. And when I say, "Soon," that's, like, ten to 15 years, or that's non-strategic for us, we would certainly consider to sell or monetize anything that's non-core for us. And of course, you know, we still have the Plains Units that we can monetize.

Leo Mariani -- NatAlliance Securities -- Analyst

Thank you very much.

Vicki Hollub -- President and Chief Executive Officer

Alright, thank you. So I want to thank you all for your questions. And I'd like to leave with three takeaways from our call. First, we're ahead of schedule with our Breakeven Plan, but we're still focused on optimizing delivery across all of our businesses. And second, we're disciplined in our reinvestment and will provide additional security to our dividend through net debt reduction. Lastly, our expanded use of returns-based incentive metrics align our executive comp with shareholder priorities. So we're looking forward to the rest of 2018. Thank you for joining our call and have a good day.

Operator

Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending. You may disconnect your line.

Duration: 64 minutes

Call participants:

Richard Jackson -- Vice President of Investor Relations

Vicki Hollub -- President and Chief Executive Officer

Cedric Burgher -- Senior Vice President and Chief Financial Officer

Jody Elliot -- President of Domestic Oil and Gas

Ken Dillon -- President of International Oil and Gas Operations

Roger Reid -- Wells Fargo -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Phil Gresh -- JP Morgan -- Analyst

John Herland -- Societe Generale -- Analyst

Pavel Molchanov -- Raymond James -- Analyst

Leo Mariani -- NatAlliance Securities -- Analyst

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