西方石油 (OXY) 2014 Q4 法說會逐字稿

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

(Operator Instructions)

Please note: This event is being recorded.

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

Mr. Degner, please go ahead.

Thank you, Emily.

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

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

In just a moment, I will turn the call over to our CEO, Steve Chazen, who will review our achievements in 2014, and provide an outlook for 2015.

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

Then, Willie Chiang will review our 2015 capital plan; followed by Vicki Hollub, who will provide an update of our activities in the Permian Basin.

As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of 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 2014 earnings press release and the investor relations supplemental schedules, our non-GAAP to GAAP reconciliation, 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 Steve Chazen.

Steve, please go ahead.

Thanks, Chris.

I'd like to start with some highlights from our accomplishments in the past year.

We executed many of our strategic initiatives, including the spin-off of California Resources, the sale of our Hugoton gas properties, BridgeTex pipeline, and PAGP units.

At the end of the year, our cash balance of $7.8 billion exceeded our total debt of $6.8 billion.

We grew our domestic oil production by 11,000 barrels a day over 2013, to 181,000 a day.

We grew our Permian resources production from 65,000 barrel equivalents a day over 2013, to 75,000 equivalent barrels a day this year.

The 2004 (sic) capital program added 395 million barrels of proved reserves; a replacement ratio of 181% before dispositions.

Our costs incurred with these reserve additions were about $6.7 billion; resulted in an apparent finding and development cost of under $17 a BOE.

We added 363 million barrels of liquid proved reserves; a replacement ratio of 223% before dispositions.

We completed the Al Hosn gas project on budget and on time, which started production in early January.

I have a few comments about the macro environment.

The confluence of US supply growth, weaker Asian demand, and extreme currency movements have led to significant decline in product prices.

Our Company is resilient, and built to weather price shocks typical to this industry.

Obviously, we have the financial resource to continue drilling at the 2004 (sic) rate.

However, the current service company cost structure is more reflective of $100 oil price environment, rather than the $50 environment we have today.

While service companies have offered modest price reductions, they still do not reflect the current reality.

We are focused on reducing our costs, which include renegotiating our supplier contracts that are not reflective of weaker oil prices.

We expect these efforts to result in a reduction in the cost of executing our capital program, as well as reducing our operating expense.

It makes little sense for us to push production, so as to sell our oil at $50 or less.

I would like to talk briefly about the impairments.

We have virtually eliminated our capital spending in the Williston Basin, on domestic gas properties, in Bahrain, and the Joslyn oil sands projects, as these have unacceptable returns in the current price environment.

As a result of a thorough portfolio review, we have [reduced] the carrying value of the assets in the areas where we are minimizing development activity.

This resulted in an after-tax charge of $5.1 billion.

These charges do not affect our cash position.

Chris will detail the charges.

Our policy has been, and will continue to be, to write down assets to approximately fair market value when we believe that the impairment is other than temporary.

In 2015, we will focus our capital spending on the core areas we operate, principally the Permian Basin.

Our capital budget is $5.8 billion, which is a 33% decline from 2014.

Two-thirds of the capital budget will be allocated to maintenance capital, and one-third allocated to growth capital.

To the start of the several long-term projects, notably the Al Hosn gas project and the BridgeTex pipeline, our 2015 capital program was on course to decline before the recent fall in product prices.

Our capital run rate in the first quarter will be higher than the $5.8-billion level, and will decline all year unless product prices significantly improve.

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

Although we will likely outspend our cash flow during the first half of the year, we expect that by the end of the year, our operating cash flow will cover our capital expenditures and dividend payments, assuming a recovery to $60 oil price environment.

Willie Chiang will provide more details on our capital program later in the call.

Despite the lower capital program, we expect to deliver 6% to 10% annual production growth in 2015, driven by the startup of the Al Hosn gas project and the focused development program we will run in the Permian resources business.

In the United States, we expect oil production to grow about 6%, partially offset by declines in NGLs and natural gas production.

Vicki Hollub will provide further details on the outlook for the US oil and gas business.

We had a successful year in growing the Company's reserve base by adding substantially more reserves than we produced.

Companywide, we replaced 174% of our production before asset sales.

We ended the year, based on a preliminary estimate, with about 2.8 billion BOEs of reserves.

Through our organic development program, replaced 181% of our production.

This estimate excludes acquisitions, asset sales, and revisions of prior-period estimates.

Our reserve replacement ratio for liquids from all categories before asset sales was 223%.

This reflects our emphasis on oil drilling.

Our total costs incurred related to the reserve additions for the year on a preliminary basis were approximately $8.3 billion.

As a result of our organic development program, we estimate an apparent finding cost of under $17 a barrel.

Our 2004 (sic) acquisitions were approximately $1.6 billion, and we booked a conservative amount of proved, developed reserves.

We expect to add incremental reserves as we exploit this acreage.

At the end of the year, we estimate that 76% of our total proved reserves were liquids, increasing from 71% in 2013.

Of the total reserves, about 71% were proved developed reserves, compared to 70% in 2013.

Over the past several years, we have built a large portfolio of growth-oriented assets in the United States.

In 2014, we spent a larger proportion of our investment dollars on these resources.

Our organic reserve replacement for the year reflects the positive results of the appraisal and development efforts, capitalizing on the large portfolio built over time.

In the United States, we replaced 266% of our production before asset sales.

We ended the year, based on a preliminary estimate, with about [1.8] BOE of reserves.

Through our organic development program, replaced 286% of our production.

The estimate excludes acquisitions, asset sales, and revisions of prior estimates.

Our reserve replacement ratio for liquids from all categories before asset sales was 306%.

Our total costs incurred related to domestic reserve additions for the year, on a preliminary basis, were approximately $5.7 billion.

As a result of our organic development program, we estimate an apparent finding and development cost of about $12 a BOE.

Through the success of our drilling program and capital efficiency initiatives, we have lowered our finding and development costs over recent years.

As a result, we expect our DD&A expense to be approximately $15 a barrel in 2015, a decrease from $17 a barrel in 2014.

This is consistent with our expectations that DD&A rate of growth should flatten out as recent investments come online, and finding and development costs come down.

The success of our organic reserve additions and the efficiencies we have achieved in our operation demonstrate the significant progress we have made in turning the Company into a competitive domestic producer.

Through the execution of our strategic initiative, we have raised enough cash to exceed our debt at year end.

Slide 14 outlines priorities of our use of cash.

This is the same slide we have shown for at least a decade.

After spending on maintenance capital, the top priority for our cash flow is to continue to increase the dividend.

We have increased the dividend for 12 consecutive years, and are committed to annual increases.

Given the uncertainty in product price, decision on the size of the increase will be made on the declaration of third-quarter dividend.

Our remaining cash flow will be allocated to growth capital, share repurchases, and acquisitions.

In 2014, we repurchased $2.5 billion of shares.

We have approximately 71 million shares remaining under our current authorization.

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

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

Thanks, Steve, and good morning, everyone.

Oxy completed the spin-off of California Resources at the end of November.

Accordingly, we have reclassified their financial and operational results to discontinued operations for our core results disclosure.

As such, our fourth-quarter 2014 core income excludes all the California results, and income on a reported basis includes two months of California results.

Total-year 2014 results on a reported basis include 11 months' contribution from the California operations, classified as discontinued.

We generated core income of $560 million for the fourth-quarter 2014, resulting in diluted earnings per share of $0.72, a decrease from both the year-ago quarter and the third quarter of 2014.

The decline in core earnings was attributable mainly to sharply lower realized oil prices on our worldwide production.

Net results for the quarter were a loss of $3.4 billion, or $4.41 per diluted share.

In accordance with the successful efforts method of accounting, which Oxy follows, we review our proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of the oil and gas properties may not be adequately recovered, such as when there is a significant drop in the futures price curve.

Under the successful efforts method, if an oil and gas property's estimated future net cash flows are not sufficient to recover its carrying amount using the period-end futures curve, an impairment charge must be recorded.

As of December 31, Oxy recorded property impairments due to the fall in the futures curve for oil as of that date.

The 2014 fourth quarter includes after-tax, non-core net charges of $4 billion.

Approximately $2.7 billion of this was a result of the sharp decline in the year-end WTI price curve that affected our domestic properties.

Most notably, this included a charge of $1.7 billion in the Williston Basin; $600 million related to our gas, and gas condensate, assets; and $350 million for other domestic acreage.

Foreign impairments amounted to $1.1 billion, principally related to our operations in Bahrain.

Additional charges included $700 million for our interest in the Joslyn oil sands project, and a $550-million mark-to-market adjustment for the carrying value related to our remaining 19% interest in California Resources.

The fourth quarter also included after-tax gains of $900 million from the sale of a portion of our investment in the Plains All American Pipeline GP, and $400 million from the sale of our 50% interest in the BridgeTex pipeline.

We continued our strong domestic oil production growth, and achieved a year-over-year quarterly production increase of 19,000 BOE per day, or about 11%, led by our Permian resources assets.

We also purchased 4.8 million shares of our stock during the fourth quarter, and ended the period with $7.8 billion of total cash on our balance sheet.

In oil and gas, our core after-tax earnings for the fourth quarter of 2014 were $368 million, $549 million lower than the third quarter of this year, and $731 million lower than last year's fourth quarter.

For the fourth quarter of 2014, total Company oil and gas production volumes from continuing operations averaged 616,000 BOE per day, an increase of 21,000 BOE per day in daily production from the third quarter, and 41,000 BOE per day from the same period a year ago.

This excludes production from the Hugoton and the California assets for all periods disclosed.

Our fourth-quarter 2014 worldwide realized oil price of $71.58 per barrel fell by $22.68, or 24%, compared to the third-quarter realizations of $94.26 per barrel.

In the fourth quarter of 2014, after-tax core income for our domestic oil and gas operations was $59 million, compared with $310 million in the third quarter of 2014, and $391 million in the fourth quarter of 2013.

On both a sequential quarter-over-quarter and year-over-year basis, results at our domestic operations were mainly impacted by lower realized oil prices and, to a lesser degree, lower NGL prices.

Higher oil production had a meaningful positive impact to both earnings and cash flow in the fourth quarter of 2014, compared to both periods.

In the fourth quarter of 2014, we experienced a narrowing of the differentials in the Permian Basin from what we realized in the third quarter of last year.

Total domestic oil and gas production averaged 321,000 BOE per day during the fourth quarter of 2014, up 6,000 BOE per day sequentially, and 26,000 BOE on a year-over-year basis.

Domestic oil production was 189,000 barrels per day during the fourth quarter, an increase of 19,000 barrels per day from the year-ago period, with our Permian resources business growing its oil production by 42% to 51,000 barrels per day.

On a sequential quarter-over-quarter basis, total domestic oil production growth was 7,000 barrels per day.

International after-tax core income was $355 million for the fourth quarter of 2014, a decline of 43% from the third quarter of last year, and 50% lower on a year-over-year basis.

The decline for both periods was driven mainly by lower realized oil prices, with the sequential quarter-over-quarter period favorably impacted by higher liftings in both Iraq and Columbia.

International oil and gas sales volumes rose by 39,000 BOE per day on a sequential quarter-over-quarter basis.

The improvement was largely due to higher volumes in Iraq, resulting from liftings that slipped from prior periods, as well as higher spending levels, higher production volumes in Columbia, along with increased volumes in the Middle East, resulting from lower prices affecting our production sharing contracts.

Oil and gas cash operating costs were $13.50 per barrel for the total-year 2014, compared to $12.56 per barrel for full-year 2013, and reclassified to exclude California.

The increase in costs reflects increased activity in downhole maintenance, and higher cost for purchased injectants.

The DD&A rate for full-year 2014 was $17 per barrel.

Taxes, other than on income, which are directly related to product prices, were $2.45 per barrel for the 12 months of 2014, compared to $2.48 for the same period of 2013.

Fourth-quarter exploration expense was $59 million.

Chemical fourth-quarter 2014 pre-tax core earnings were $160 million, compared with third-quarter results of $140 million, and $128 million in the year-ago quarter.

The sequential improvement primarily reflected lower ethylene and energy costs, partially offset by lower vinyls pricing, and a reduction of volumes across most product lines, due to a combination of maintenance outages, holiday shutdowns, and customer initiatives to reduce year-end inventories.

Midstream pre-tax core earnings were $168 million for the fourth quarter of 2014, compared to $155 million in the third quarter, and $106 million in the same period a year ago.

Phibro's domestic trading book was closed in the fourth quarter of 2014, and we expect to wind down the remainder of the business in the current quarter.

As such, Phibro's results have been eliminated from all core income periods.

In the 12 months of 2014, we generated $9.4 billion of cash from continuing operations, a decline of approximately $1 billion compared to the year-ago period.

Capital expenditures for 2014 were $8.7 billion, net of partner contributions.

Last year's capital outlays included $1.1 billion associated with the Al Hosn gas project, including $470 million related to the rail and sulfur handling facilities, and $285 million for the BridgeTex pipeline.

We received proceeds of $4.2 billion from the sale of assets, which included fourth-quarter proceeds of $1.1 billion from the sale of our investment in BridgeTex, $1.7 billion from the sale of a portion of our investment in Plains All American Pipeline GP, as well as $1.3 billion from the sale of our [Hugoton] assets in the first quarter of last year.

We spent about $1.7 billion on bolt-on property acquisitions, of which $1.3 billion was spent in the fourth quarter on a single acquisition in the Permian, totaling 100,000 net acres, and including a modest amount of oil production.

In October, we received cash proceeds of $4.95 billion from the bond offering completed by California Resources.

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

We paid the fourth-quarter dividend and repurchased our shares in December using the restricted cash, resulting in a $4-billion balance at December 31.

We received an additional $1.15 billion of cash from California Resources concurrent with the spin-off in late November.

The use of those proceeds is unrestricted.

We returned $4.7 billion of cash to our shareholders by paying $2.2 billion in dividends, and repurchasing 25.8 million of our shares for $2.5 billion.

Last year's share repurchase activity has the benefit of reducing our current dividend outlays by approximately $75 million.

Our cash balance, including restricted cash, was $7.8 billion at December 31.

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

After excluding the impact of non-core adjustments, and discontinued California operations, our 2014 return on equity was 9%, and return on capital employed was 8%.

The worldwide effective tax rate on our core income was 39% for the fourth quarter of 2014, and 41% for the total year.

Focusing on 2015, our capital program this year is expected to be about $5.8 billion, a decrease of 33% from our 2014 spending level of $8.7 billion.

Willie Chiang will discuss the specifics of the 2015 capital program in a moment.

Using a $55 WTI and $60 Brent price curve, we expect total Company production to be between 630,000 and 650,000 BOE per day in 2015, or an increase of roughly 6% to 10%.

Domestically, we expect our oil production for the total year to grow in the 6% range, with the increase coming from the Permian resources business.

We expect gas volumes to decline modestly as we cease development activities in our gas properties.

In the first quarter, we expect to lose approximately 4,000 BOE per day production in our Permian Basin operations due to weather-related shutdowns and freezing conditions that occurred during January.

Domestic gas production is expected to decline from fourth-quarter levels, resulting in a slight sequential production decline on a BOE basis.

We expect our international volumes to increase in the first quarter, with the Al Hosn gas project having started up earlier this month.

Volumes from Al Hosn should average roughly 20,000 BOE per day in the first quarter, as the facilities ramp up through the first half of the year.

Full-year 2015 volumes from Al Hosn should average about 50,000 BOE per day, with more than 40% of the production coming from NGLs and condensate.

Production volumes should also be positively impacted from our production sharing contracts that are sensitive to the decline in oil prices.

Oil and gas DD&A expense is expected to be approximately $15 per BOE this year.

Combined depreciation for the midstream and chemical segments should be approximately $675 million.

Price changes at current global prices affect our quarterly earnings before income taxes by $32 million for a $1.00-per-barrel change in oil prices, and $7 million for a $1.00-per-barrel change in NGL prices.

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

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

Our first-quarter 2015 exploration expense is anticipated to be about $30 million pre-tax.

We expect our first-quarter 2015 pre-tax chemical earnings to be about $140 million.

Lower chloro-vinyl margins are the primary driver for the sequential decrease in earnings.

Using current strip prices for oil and gas, we expect our 2015 domestic tax rate to be at 36%, and our international tax rates to be about 65%.

I will now turn the call over to Willie Chiang, who will provide more detail on our 2015 capital program.

Thanks, Chris.

Good morning, everyone.

As you now know, our 2015 capital program is expected to be $5.8 billion, a 33% reduction from our 2014 capital program.

All business segments will see cuts in capital spending versus the 2014 levels, with the exception of chemicals, which is in the peak year of spending for the Ingleside ethylene cracker JV project.

Despite the lower capital program, we expect to deliver the production growths in 2015, as Steve has said.

Now let me expand on the 2015 program, of which 80% is in the oil and gas segment, and 10% each is in the chemicals and midstream segments.

Domestic oil and gas capital will be about $2.5 billion or 43% of our total capital program, a decline of about $1 billion from 2014 levels.

Overall spending levels in the Permian will decline slightly, and significant reductions will come from Williston and south Texas, which are most impacted by the sharp declines in product prices.

Vicki Hollub will provide more details on that later in the call.

International development capital will be about $2 billion or 33% of our total capital program.

Spending levels in the Middle East, North Africa, MENA, region will decline by approximately $1.4 billion, mostly from the Al Hosn gas project completion, Qatar, and other mature projects.

Exploration capital is expected to decrease significantly from the 2014 levels to roughly $150 million.

Our 2014 exploration program was successful in supporting the appraisal and delineation of a strong inventory of drilling locations, which is the basis of our development program this year.

Chemical segment capital will be about $600 million, which includes the Ingleside cracker project that we expect to complete late 2016, and commission in the first quarter of 2017.

We expect Oxy Chem to be free cash flow positive through the construction of this project.

US midstream capital will be about $600 million, a decrease of about $150 million from the 2014 levels, driven primarily by the completion of BridgeTex pipeline.

Key projects include the continued development of the Ingleside terminal for both propane and crude export terminalling, as well as gas processing infrastructure in support of our key development programs in the Delaware Basin.

The 2015 capital program I have described ramps down over this year, and where we expect to end the year at a balanced free cash flow run rate, which will cover capital, interest and dividend payments at the $60 oil environment.

It also allows us to develop profitable production growth, and allows us to continue to develop the key strategic projects in our chemicals and midstream segments.

I would like to take a few minutes to share with you the status on our reductions of our cost structure.

Clearly, lower oil price environments require lower cost structures to be competitive.

Our 2015 plan assumes a very conservative amount of pricing concessions from our suppliers of roughly $250 million for key services.

If the market environment remains where it is, we expect to see this increase to $500 million or more, which will give us the flexibility to increase activity.

We have been very engaged with our suppliers and service providers to capture immediate reductions in costs, ranging from 10% to 40%.

In many cases, we have amended existing agreements to tie discounts to oil price.

The lower the oil price, the greater the discount needed to meet the market environment.

We are in the early stages of this process, and have finalized agreements with about half of our key suppliers to date.

Most of the cost savings that we have incorporated are capital costs, but we also expect operating cost reductions from the $15 per BOE domestic operating cost level.

Beyond what we normally look at pure lifting costs of the Business, there are a number of cost categories that comprise the total operating costs.

Some of these categories are fairly consistent year to year, and include labor, generally operating support and staff, plan expenses, pipeline transportation costs, surface maintenance.

This activity allows us to produce our product reliably, safely and responsibly.

Now, highlighted are a number of categories where we do expect to see significant reductions, and are much more discretionary in nature.

These include well workovers, well enhancements, downhole maintenance, and purchased injectant costs, primarily CO2.

Clearly, in a low product price environment, many of these activities are just not economic to pursue.

We also expect to see energy cost reductions, which are linked to oil and gas prices, so they too will come down in this price environment.

This should give you more perspective on another key area of opportunity that we are working hard on, and we will share more specifics with you as we develop more certainty around market environment, and other optimization and efficiency improvements.

I will conclude my remarks by emphasizing that our capital allocation is very dynamic in nature.

We will proactively manage our program, and we have ample flexibility to respond to both stronger and weaker conditions.

I will turn the call over now to Vicki Hollub, who will review our 2015 domestic oil and gas plans.

Thank you, Willie.

Today I will review the highlights of our Permian resources activities in the fourth quarter, and then I will provide more details about the 2015 capital programs in our US operations.

In the fourth quarter, Permian resources achieved daily production of 84,000 barrels of oil equivalent per day, which is a 9% increase from the 77,000 barrels of oil equivalent per day that were produced in the third quarter.

With regard to oil, we produced 51,000 barrels of oil per day for the fourth quarter.

This is a 42% increase from a year ago, and a 19% increase from the previous quarter.

During the fourth quarter, our capital expenditures were $791 million.

We operated 29 rigs, and drilled 85 wells, including 56 horizontals.

We placed 70 wells on production, including 44 horizontals.

At year end, 11 wells were on flow-back, and 61 were not yet completed.

In the Delaware Basin, we operated 14 horizontal drilling rigs and one vertical drilling rig in the fourth quarter.

We drilled 47 wells, and placed 39 wells on production.

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

These wells achieved an average peak rate of 1,500 BOE per day, and a 30-day rate of 1,190.

We are extremely excited by the results achieved on the Peck state 258 number 6H, where we optimized the landing point and cluster spacing.

This well achieved a peak rate of 2,400 BOE per day, and a 30-day rate of 1,760.

Additionally, we placed our first two 7,500-foot lateral wells, the Buzzard state number 9H and number 10H, on production with excellent results; both were completed in the Wolfcamp A. The Buzzard state number 9H achieved a peak rate of 2,020 BOE per day, and a 30-day rate of 1,780.

We are achieving excellent initial results on our wells with sand concentrations ranging from 1,750 to 2,250 pounds per foot.

For example, our Chevron Mineral 17-5 well achieved a peak rate of 1,800 BOE per day.

In New Mexico, we continue to be pleased by the performance of our Bone Spring wells.

Recently, our Cedar Canyon 27 state 4H was placed online with an average peak rate of 1,790, and a 30-day rate of 1,030 BOE per day.

In the Midland Basin, we operated 10 horizontal drilling rigs and four vertical drilling rigs during the fourth quarter.

We drilled 38 wells, and placed 31 on production.

In the Spraberry, Wolfcamp A and Wolfcamp B benches, we placed 17 horizontal wells online with an average peak rate of 950 BOE per day, and a 30-day rate of 790.

To date, we have placed 10 Spraberry wells online with an average peak rate of 900 BOE per day, and a 30-day rate of 850.

Last quarter we discussed our South Curtis Ranch 3526H well in the lower Spraberry.

We are excited to report the six-month average production for this well was 740 BOE per day.

In one of our new development areas, the Merchant 1411 well achieved a peak rate of 1,560 BOE per day, and a 30-day rate of 1,140 from the Wolfcamp A. The aggressive exploration and appraisal programs we completed in 2014 have helped us to clearly identify our best benches, and to achieve significant improvements in well productivity and operational efficiency.

We will continue to improve these results in 2015.

Now I will provide additional details about our 2015 capital plans at our domestic operations.

Our most significant capital reduction will come in our Mid-Continent business unit, which includes our Williston operations and our gas properties in the Piceance in south Texas.

We plan to spend $285 million in 2015 versus $570 million spent in 2014.

The 2015 capital program will focus on maintenance activities, along with high-return workovers.

This fits with our strategy to focus capital on higher-margin oil production.

In the Permian Basin, we have two distinct, but synergistic businesses: resources and enhanced oil recovery.

Our resources business provides the unconventional portfolio and expertise to achieve accelerated growth, supported by our EOR business, which provides the cash flow from efficient, high-volume production.

In Permian resources, our capital expenditures will be approximately $1.7 billion.

This is a $200-million reduction from 2014 expenditures.

We plan to operate an average of 19 rigs, and drill approximately 167 horizontal wells, which is equal to the number of horizontal wells we drilled in 2014.

Additionally, we will drill only 48 vertical wells versus the 137 vertical wells drilled in 2014.

Vertical wells are drilled to hold acreage or to appraise new benches.

Our 2015 capital program will focus on the development of our best benches in concentrated geographic areas.

In the Midland basin, our development activity will be mainly in South Curtis Ranch and Merchant.

Here we plan to drill 45 Spraberry wells, where our performance is matching a 750,000 BOE type curve.

In the Delaware basin, we plan to drill 67 Wolfcamp A wells, and a concentrated number of leases in the greater Barilla Draw area.

Our Wolfcamp A wells in the Delaware are exceeding a 900,000 BOE type curve.

In New Mexico, we plan to drill 22 Bone Spring wells.

We will execute this targeted capital program utilizing a manufacturing approach, which will include the efficiencies of pad drilling, batch drilling of the vertical and lateral sections of the well, along with zipper fracs.

This strategy will enable us to grow our production at a higher rate with less capital than in our 2014 appraisal program.

In the first quarter of 2015, we plan to operate an average of 29 rigs.

We expect to drill 85 wells, and place 108 wells on production, including 63 horizontal wells.

We are on pace to have 42 wells on flow-back or on production in January.

Permian resources has a sufficient inventory of wells to continue profitable development in a low-price environment.

Based on our current cost structure, we have the ability to continue drilling profitable wells for several years.

We are taking the following actions to ensure we can deliver even more locations in this low-price environment.

First, we will continue our investment in reservoir characterization and optimization of key variables such as well-bore spacing, lateral length, proppant concentration, surfactants, cluster count, and spacing.

These investments drive resource recovery, and are fundamental at any price.

Second, we will continue to apply enhanced manufacturing principals to our development program.

This will enable us to achieve efficiencies at an accelerated pace.

Third, we will continue our efforts to enhance our base management and maintenance activities.

This will ensure optimized production levels, while minimizing associated operating costs.

Lastly, we continue to aggressively work with our suppliers to improve operating productivity, eliminate constraints, and lower costs.

These actions are consistent with the long-term strategy I have discussed in previous calls.

I am encouraged by the urgency and actions our employees and contractors have already demonstrated in delivering on these initiatives.

I will now discuss our Permian EOR business.

While it hasn't drawn much attention in the last couple years, with the industry focused on high-growth resource programs, our Permian EOR business remains very profitable.

Oxy is the leader in Permian basin CO2 flooding, with over 30 active floods, and 40 years of experience.

This business has weathered prior downturns with resilience, and the low decline of these large properties provides a stable base to our production at an advantaged cost.

The Permian EOR business has the agility, scale and cost structure to operate in an ultra-low-pricing environment.

Currently, our total cash costs in Permian EOR is $30 a BOE, as shown on the slide.

This takes into account the cost reductions that we have already achieved.

If prices stabilize at today's level, or continue to decline, all costs that are linked to oil prices would also decline, including energy, CO2, production taxes, and discretionary well maintenance activities.

For example, in a $35-per-barrel oil price scenario, our total cost would reduce to approximately $22 a BOE.

Our DD&A cost is approximately $10 a BOE.

We continue to see opportunity for investment in CO2 projects in the current oil price environment.

Last year we drilled 277 infill wells, and continued construction of facilities for new CO2 projects.

When completed, our new project at South Hobbs will develop 28 million barrels of oil equivalent of reserves at a cost of $10.60 per BOE.

The CO2 floods have remained a strong business through technology advancement that improves recovery from our large portfolio of conventional reservoirs.

In the Permian, Oxy operates reservoirs that collectively contained approximately 18 billion barrels of original oil in place.

Hence, even small improvements in recovery efficiency can add significant reserves.

An example of this has been the recent trend towards vertical expansion of the CO2 flooded interval into residual oil zones, or ROZ, targets.

Over the last few years, we have had an ongoing program of deepening wells, with 109 wells deepened in 2014, and 81 wells planned in 2015.

This activity escapes much attention because we utilize work-over rigs to drill the extra depth into additional CO2 floodable sections of the reservoir.

These low-cost projects add reserves at development rates ranging from $3 to $7 per BOE.

These opportunities exist under many of our CO2 projects, and thus far, only a fraction of the CO2 flood wells have been deepened.

The Permian EOR 2015 capital expenditures will be approximately $500 million to continue expansion of CO2 floods and water floods.

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

We will complete construction and begin injection at the new South Hobbs project.

Additionally, we will also start construction of a significant expansion at the successful North Hobbs CO2 flood, where CO2 flooding has added a sustained 5,300 barrels of oil per day to the unit's production since this project began in 2003.

Our EOR business has unrisked gross resource potential of up to 1.9 billion barrels, providing us with a vast inventory of future CO2 projects which could be developed over the next 20 years, or accelerated, depending on market conditions.

Our current strategy for this business is to invest sufficient capital to maintain current production, thereby providing cash flow to support growth in our Permian resources business.

By exploiting natural synergies between our EOR and resources businesses, Oxy is able to deliver unique advantages, efficiencies and expertise across our Permian Basin operations.

In closing, our 2014 exploration and appraisal programs have successfully set us up for a strong 2015 development program in Permian resources.

Our portfolio of high-quality assets combined with our value-oriented discipline enables us to deliver efficient growth.

We will execute a focused development strategy in 2015, and continue to pursue step changes in well productivity and cost structure.

Our first-quarter production of 2015 will be negatively impacted by approximately 4,000 BOE per day due to the winter weather events that occurred in the Permian Basin in January.

But we do expect to deliver our previously stated target of 100,000 BOE per day from Permian resources in 2015.

Our combined EOR and resources production is significant, and accounts for 15% of the production from the Permian basin.

Our development program, along with the synergies delivered by our resources, EOR and midstream businesses, have us well positioned to meet the challenges of this lower-price environment.

Now I will turn the call back to Chris.

Thank you, Vicki.

Now we will open the call up for questions.

Thank you.

(Operator Instructions)

Our first question is from Doug Leggate of Bank of America Merrill Lynch.

Please go ahead.

Thanks.

Good morning, everybody.

I wonder if I could take two, please.

Vicki, this one's probably for you.

To be absolutely clear, in this current oil price environment, not the $55 that you have put in the plan, but is the Permian program delivering positive returns?

And if you could give some color as to what royalty ownership or what royalty rates you might have in the program for the current year in the Delaware basin.

Yes, Doug, currently our program at today's prices will deliver about 15% to 20% rates of return.

And the reason for that is, we had an aggressive program, appraisal program in 2014, so we are targeting in 2015 our best benches in our best areas.

And we have had really good success recently with improving our completion designs.

So we expect the returns to be in the 15% to 20% range.

And if you will refer back to the chart I included in the presentation in Q3, you will see that if you look at the areas where we are developing, I think I have some numbers there that generally would enable you to get to the net interest.

Okay.

Not to belabor the point, Vicki, but what kind of inventory in terms of at the current pace, the wells would achieve or the program would achieve at $45 oil?

Is that high-grading the portfolio or is that a multi-year inventory that you would need to achieve that?

We have high-graded the portfolio, but we expect to be able to, at least this pace, go at least 3 to 5 years with the inventory that we have.

And if prices continue to improve, with respect to the cost structure, and I don't mean oil prices, I mean if our cost structure continues to improve based on prices, we expect that inventory to increase.

So we expect over time to be able to increase the inventory that we have today.

But at today's pace, it would be about 3 to 5 years.

Okay.

Thank you.

My follow-up is and I'm not just going to go off on the question of operations, but Steve, I wonder if I could go back, just to the progress on the asset sales in the Middle East.

Any updates you can provide, especially now that Al Hosn is onstream, and given that the [Ahlman] contract expires this year, could you help us with how you see things changing in this oil price environment, if at all?

Of course, the countries are say that the prices will quickly rebound once the evil shale producers stop producing.

But I think until that happens, I think that it is going to be slow.

I mean obviously, the countries are affected by this.

They are actually affected more by the decline in oil prices than anybody really.

So I suspect that it will be slow.

I think Ahlman will move along all year.

We just don't know what is going on in Abu Dhabi at this point.

Okay.

I will leave it there.

Thanks, everybody.

Thanks.

Our next question is from Paul Sankey of Wolfe Research.

Please go ahead.

Good morning, everyone.

Steve, talking again back to the CapEx program, it seems that you have used the strip to come up with the 2015 number.

I just wondered how much lower would you have to take CapEx if we stay at the smaller $45 environment for let's say another year?

For another year, it gets a little more complicated.

The capital spending on the chemicals and the midstream stuff will fall off naturally going into next year.

So the capital would come down anyway.

We have only built in the cost savings that have sort of been achieved at this point.

And there is at least another $250 million and maybe another $500 million in savings just from the suppliers if prices continue to be low, because we basically, for a lot of them, we have indexed how much we are paying to the oil price.

So I don't really know exactly what it would be, but I would guess if you used -- if it is 60, we are covering everything at the end of the year.

There is some other stuff that would be reduced and it is probably a little lower than the 60 actually, and so if you said okay, it is going to be $10 less, $10 less is $1 billion.

So we would have to reduce the capital by $1 billion.

Most of that, we would get from suppliers, but there would be some things that would have to be cut.

Thank you.

And then a follow-up would be, have you considered selling Oxy and have you considered any major acquisitions?

Thank you.

Right now, people are cash flow challenged so I suspect selling Oxy is probably not real likely.

I looked at Chevron.

It looks they don't have any free cash.

We haven't considered any major acquisitions.

It is way too early to be talking about acquisitions.

There is still a lot of whistling in the grave yard going on.

And way too early to consider any kind of acquisitions.

Again, we generally are not interested in public acquisitions.

That's helpful, Steve, thank you.

Our next question is from Doug Terreson of Evercore ISI.

Please go ahead.

Good morning, everybody.

Nice new name.

How about that.

I had a question about divestitures as well.

There's been some commentary in the market about possible divestiture of the Al Hosn project, which you guys have just completed and so just wanted to ask you, is that a possibility?

If you could provide some color on that and again, it wasn't your commentary, it was that from others, but can you give us an update on the strategic attractiveness of that position?

Let's talk about what it is.

We have already spent the money.

So there is not really much capital going forward.

There might be an expansion, which is relatively cheap capital, out a year or so.

Putting that aside, in a crappy oil price environment, probably generate about $300 million of free cash and sort of a decent one, about $600 million of free cash a year.

So if you multiply it out by the 25 years that remain roughly, you multiply through, you get somewhere between $7.5 billion and whatever it is, $12.5 billion of cash generated over the 25-year period.

So from our perspective, for a company that pays a lot of dividends, and that sort of thing, having that sort of asset makes good sense to us.

If on the other hand, for a variety of reasons, somebody wanted to buy 20%, 30% of it, to free up cash for something that maybe works better, I guess we are open to that.

But you know, only in a -- if you look at it intrinsically, for somebody who pays a lot of dividends, I think it is a pretty good asset over time.

it seems so, and then also, there is a lot of commentary about Oxy's historical proficiency and insularly recovery.

So I wanted to see how are you thinking about the opportunity in Mexico, or potential opportunity, meaning do you consider this to be an area of natural alignment for Oxy?

And if you do, how do you think about the opportunity in Mexico?

There's two issues, like always in foreign activities.

One is the quality of the asset being offered.

And I think, intrinsically, they have some decent enhanced oil recovery assets on offer.

The other part of it is, what is the financial arrangements?

If you look at some of the other places, I won't say where, but look at some of the other places where intrinsically the asset might work at $20 a barrel or something like that, but if you lay the contract over, it doesn't really work at today's prices.

And I think that is the issue in Mexico.

While the asset may be attractive and you can get a lot of -- if you had 100% of it, it would be something that would work pretty well.

But they have taken a pretty aggressive view about contract terms.

I think they took the Chinese menu approach where they picked one from every column and everybody's contract.

So I think they got a pretty difficult contract to want to do it and we're not doing it for advertising expense.

I think we would rather, frankly, put the money into the CO2 projects in the United States where we have low royalties, fact is in some cases we own the royalties, than to fool around with some ridiculous contract in hopes it gets better over time.

Okay.

Thanks a lot, Steve.

Thanks.

Our next question is from Leo Mariani of RBC.

Please go ahead.

Hey, guys.

Obviously, a lot of focus here in terms of how you guys can kind of conservatively manage things.

Wanted to flip the question around and just get a sense, if we do start to see an oil price recovery in the second half of the year, in 2016, how quickly you can bring rigs back in the Permian.

Additionally, is there any kind of loose price framework we should think about, where if we do get to $70, is that the number where you start adding rigs?

Anything you can help in terms of price would be great.

I think the answer to your question is there's a lot of rigs around in the Permian and there's more available every day.

So I don't think bringing rigs back is going to be a problem.

I think the program has to be somewhat disciplined.

We will be cautious in adding rigs, because while the prices may rebound, it may go back down again.

I'm more concerned, really, about the demand issues in the world than I am how much the US business is producing.

But I think if you look at it and said -- clearly, if you hit the $60, the program will be the way we've described it.

As you get to $70, you may be a little more aggressive, and as you get north of $70, I think we would be somewhat more aggressive.

But I really think that, if you look at -- if you were able to see the layers, inside the company, we've got it all matrixed.

We can actually figure what makes sense at whatever price you want and so our program going forward would reflect that expectation.

But right now, our expectation is conservative, I would guess.

All right.

Could you just talk a little bit about the importance of returns on the drilling program versus desire to stay cash flow positive or cash flow neutral when you include dividends?

Obviously you've focused on getting back to this cash flow neutrality, exiting the year at 60, so as we think about a recovery case in 2016, how much are you focused on making sure you don't outspend versus hey, if the returns are good, at 70 we are willing to outspend.

Can you talk to that?

You've got to be pretty certain about your returns before you outspend.

No offense to any oil engineers, but they tend to be a little more optimistic than the actual outcome.

The corporate management will be fairly conservative about things, so we need some margin of error.

A lot of damage being done in the business, I think people underestimate the amount of damage being done.

When this cycle, when this current down cycle is complete, whether it is a year or two years, everybody's balance sheet is going to be not quite as good as when they started.

We are starting at a good spot, but I think even the large companies will have more debt-laden balance sheets and not really much to show for it.

So I think you just got to be pretty careful in this environment about what you are doing.

No one really, even though the price may recover in the back half of the year, I am still concerned about world demand for oil.

Although I am heartened to see that in the United States, at least, the lower gasoline prices have created more people riding around in big cars.

So we are doing all right.

We are riding around the corner.

That makes sense for sure.

Lastly, in terms of M&A, I wanted to clarify some of the comments, you certainly talked about sort of a challenging market for acquisitions at this point in time.

It sounds like bid/ask spreads haven't reset, but I also hear in the prepared comments that you made an acquisition in the fourth quarter of 2014 for 100,000 acres in the Permian for around $1.3 billion.

Can you give us more color on what you picked up there and what you think about it?

It was early in the quarter.

We're probably a little early in the acquisition, I think, the acquisition cycle.

We got, we think, a price that works in this environment.

It is good acreage and we picked up a modest amount of production.

The goal of the acquisition program in the Permian is to add to our current position so we can drill more efficiently.

It is not really to get more acreage.

We've got plenty of acres.

The question really is, can we fill in our play, what we currently own and allow us to drill more efficiently without moving the rigs so much.

This sort of acquisition was designed with that intention, that would allow us to be more efficient.

Without efficiency gains, I think acquisitions are not very interesting.

Okay.

Thanks a lot.

Our next question is from Jeffrey Campbell of Tuohy Brothers Market Research.

Please go ahead.

Good morning.

First, just a couple of quick Vicki questions.

I noticed that the Delaware basin second Bone Spring had been re-rated from appraisal to development from last quarter to this one.

Is that the zone that you're focusing on in New Mexico?

Yes, it is.

We are only going to drill second Bone Spring wells in New Mexico in 2015.

Okay.

Great.

It sounded like the reduced vertical drilling is tied to less appraisal work.

Can you identify which appraisal zones are likely to be most affected by the reduced 2015 CapEx?

It would really be the zones, the benches that are away from our current development areas.

For example, we appraised the benches at South Curtis Ranch and several in the Barilla Draw area.

What we are going to try to do now, is focus on the development of those areas.

Our appraisal program was so far ahead, we still know a lot about some of our other areas.

We just wanted to get to manufacturing mode so we could improve our cost efficiency.

So we are still -- we are pretty much way ahead with our appraisal program right now.

The thing that we want to do next is to continue to improve on our completion efficiency.

Okay.

Thank you.

And Steve, this is the last question, you have spoken some about concerns on demand.

Can you outline where you look for signs of improvement?

Particularly as we all can expect that US oil production is going to increase as oil prices begin some kind of recovery?

Well, I think if I look at US oil production, it will probably increase in the first and second quarter and maybe the rate of increase in the third quarter will fall off and maybe there will be some decline in the fourth.

The main consumer of oil today is China.

Any recovery in Europe would be helpful, but it is not a driver.

So it is China and maybe India.

Also the Middle East has been a large consumer of oil recently.

And the current environment is -- it is just hard to say whether that growth will continue or not.

I think the world economy, I think that is the big question mark going forward.

If we get demand growth, lower oil prices stimulate demand, this current situation will be over fairly quickly.

If we don't, this could drag on quite a while.

Okay, thanks very much.

Our next question is from Jason Gammel of Jefferies.

Please go ahead.

Thanks.

I wanted to ask a question about the importance of operational momentum in the Permian Basin.

Where I am coming from here is, you are generating very acceptable returns at current prices, but that could potentially be significantly higher rates of return, assuming a recovery in the oil price.

So given that you are more or less flat on horizontal drilling activity, what stops you from, let's say having the rig count in the first half of the year and then moving up to a much higher count in the back half of the year?

It is basically the contractual position we have.

We have contracted for some rigs that basically come off at mid-year.

And by the time you drill -- I mean think about the timing.

Let's say you actually drill a well in the first quarter.

It is the third quarter before you actually get the revenue.

So the stuff in the first quarter will basically be a third and fourth quarter production for us.

But I think we have some contracts that need to roll off.

And that's really controlling the timing more than anything right now.

Okay.

So there is nothing related to utilization of the work force and efficiencies that could be lost if you did have a sudden shutdown or anything --

There is always an efficient -- if you all of a sudden stop in the middle, it's always going to be a problem.

It's got to be a phase-down.

But it is contractual.

And the notion that there maybe there will be some recovery in the back half of the year, and you need to drill the wells in this first and second quarter to have production in the back half of the year.

We are pretty cautious about the whole thing.

You just can't send things to zero, it's just an impractical thing to do right now.

We are doing the best we can to manage through it.

And I think we will be all right.

Okay.

I could ask one more on a completely unrelated topic, you mentioned that the restricted cash was used to pay the dividend in the fourth quarter.

Should we think about in a low price environment, restricted cash essentially funding the dividend and how does that affect then the pace of share repurchases?

You said that the 71 million you still ultimately expect to buy in on the share repurchase program, but could that be a five-year period or are you thinking more like a two-year period?

I wouldn't get wrapped around the axle on this restricted cash stuff.

Cash is reasonably fungible.

All we are doing is showing the account paying down.

Rather than keep more restricted, we just say the dividend comes out of that bank account.

So it has to come from somewhere.

We don't really know about the pace.

We are price sensitive.

I'd point out that really the domestic program last year had an F&D, if you cut through all of the BS, of $13, $14 and we expect to bring that down some more.

So we are running a pretty profitable program.

Maybe not at $25 oil, but certainly in the $50s.

As far as the pace of the share repurchase, the stocks are volatile and when there's negative volatility, I guess volatility is always used negatively, nobody ever talks about upside volatility, but down side volatility, which I am sure will come at some point in this, that's when we will step up and buy a lot of shares rather than just treat it as a constant flow.

So I don't really know.

We set aside a fair amount of money for that this year.

But if prices are more attractive, we will spend more.

I don't really have a budget in the usual sense of the word.

And would you want to comment on what you would find an attractive price, Steve?

No, I wouldn't like to comment.

I figured that.

Thanks very much.

Our next question is from Brian Singer of Goldman Sachs.

Please go ahead.

Thank you.

Good morning.

I wanted to follow up on a couple of the earlier questions.

First, you mentioned that you would have flexibility to increase activity if you can get another $250 million in savings.

Can you just talk more to what that scenario looks like?

Would that mean your portfolio would achieve attractive returns at $60 Brent and you would ramp back up in the areas that you are currently ramping down?

I.e.

you would recommit to the mid-con or would you ultimately look to focus more on the Permian incrementally when prices --

It would be all Permian.

The mid-con is, well, putting aside North Dakota, is basically gas.

So the Brent price is sort of irrelevant.

And it really can't compete for dollars for quite a while against the Permian.

North Dakota has this huge differential to price right now.

So that's really what is discouraging us up there.

So I think you should plan that in a $60 environment or $65 environment or whatever you are thinking, that we would spend more in the Permian.

The savings, $250 million, we could add about 3 rigs on an annual basis to cover that.

It was running about $100 million or a year or so, it would probably run a little less now.

So that is a way to think about how much more we would do.

But we've got a fair inventory and as prices move up, the inventory obviously expands.

Great.

Thanks.

And then back to the Permian acquisition, in looking at that 100,000 acre deal, you mentioned the strength was the efficiency that it has with existing positions.

Based on the placement of your existing acreage within the Permian, can you talk to the scope for how many more fill-in acres would be optimal for you with your acreage positions and whether you see those opportunities becoming available?

We don't know about opportunities because some people may have debt and they probably don't want to sell for less than their debt.

We just don't have any way of pacing that at this point.

We don't really know.

If we found more in the Barilla Draw area that would be real interesting.

There is acreage around there that is held by others and some, a little bit in the Midland basin, but that is what we have.

I don't know whether it is 300,000 acres or 200,000.

It is not millions of acres.

Great.

Thank you for the color.

The next question is from Ryan Todd from Deutsche Bank.

Please go ahead.

Thanks.

Good morning.

Maybe a couple more follow-up questions on the Permian.

Can you talk a little bit about what you're seeing from a well performance point of view in 2015 and 2016?

Production targets seem largely unchanged despite CapEx cuts.

Is this efficiency gains, better well performance, combination of both?

It is.

We haven't changed our 2016 target yet, because we are still anticipating that if prices were to go up, we would have the flexibility to add rigs.

We may have to adjust that a little bit toward the end of this year if prices remain where they are.

But one of the things that we are encouraged with, is we certainly are seeing better performance, particularly in the Barilla Draw area and particularly with the last well that I mentioned in the call today.

We are seeing not only opportunities to improve our landing points within the benches, but our completion efficiencies are improving and we are really encouraged with what we are seeing there and with what we are seeing from the Spraberry in the Midland basin.

Thanks.

And then on costs at this point, the 2015 budget, your per well budget costs in the Permian in 2015, what is it relative to 2014 costs and is that mostly efficiency gains or do you have anything priced in for price deflation or is that additional upside?

We've priced about $250 million in for cost reductions that we pretty much achieved.

And we expect to get some more, but we certainly priced that in already.

And efficiency gains are built in.

Efficiency gains really come from focusing on a few places rather than going all over creation.

That's really what causes it and we built that in.

Okay.

So the additional $250 million that you had highlighted on the slides, there is certainly potential down side from a price deflation point of view, but efficiency gains are at least mark-to-market from where you guys are right now, I guess.

I guess that's right.

Okay.

Thanks.

I will leave it there.

Our next question is from Evan Calio of Morgan Stanley.

Please go ahead.

Good morning, guys.

A few quick follow-ups for me.

First, on the buyback, I presume most of the buyback in 4Q was executed after or in December after the spin?

Yes.

Second, I know that you're price sensitive and/or I would say price aware, so do you see the flexibility to use your currency for adding assets, if your view was that it were to be expensive relative?

I think I used stock once in the last 20 years and regretted it ever since.

So maybe I have been doing this too long, too good of a memory of bad outcomes.

If you are going to use your stock, you really have to make sure that whatever you are doing is significantly accretive.

Cash, at least cash, you are you only paying 3% or whatever it is interest, but if you're using stock, we're paying almost 4% in dividends.

Even putting that aside, you don't want to dilute the quality of your portfolio with some wacky deal.

And so if you are going to gamble on wackiness, you probably ought to gamble with cash rather than stock.

A follow-up on the Permian acquisition that you made in the quarter, any color in terms of location, well inventory?

It is a Midland basin acquisition.

And there is, just a matter of price, when you talk about locations, you also got to factor in price.

I think going in, I think it was about 2,700 locations.

Okay.

And will you expect activity there in 2015 or will that be part of your focus area?

Yes, we do.

Is that due to economics or because it is non-HBP?

It is economics principally.

There is some non-HBP.

We will probably use a vertical rig there to keep some of the acreage.

Great.

Thanks for taking my questions.

Thank you.

Our last question is from Matt Portillo of TPH.

Please go ahead.

Good morning, all.

Good morning.

Just a quick follow-up question in regards to your Permian rig count and spending program.

I believe you mentioned you're running roughly 29 rigs coming into the first quarter.

I was curious if you could give us a little bit of color on the cadence of that rig drop as you move through the year to average the 19 rigs in 2015?

And then I have a follow-up question in regards to your overall capital program.

Currently, we are going to average also 29 rigs in Q1.

And then toward the end of Q1, we start to ramp down and by Q3, the beginning of Q3, we will be at 15 rigs and at 15 for the rest of the year.

Thank you.

In regards to your corporate capital program, you mentioned the first quarter will be a bit heavier in terms of CapEx versus the back

You can see that in the rig count.

It just flows out of that rig count.

Right.

And to try to get a little bit of color around how we should think about the magnitude of the change on CapEx, is there any color you can provide as we think about the exit capital program you have talked about in the fourth quarter of 2015, how would you think about the magnitude of the change over the year?

Willie can answer that.

I would say directionally, we are starting off at about $1.8 billion in Q1 and ramping down to about $1.2 billion, rough numbers.

Perfect.

That's very helpful.

Thank you very much.

This concludes our question-and-answer session.

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

Thank you, Emily and thanks to everyone for participating today.

Bye.

The conference is now concluded.

Thank you for attending today's presentation.

You may now disconnect.