西方石油 (OXY) 2014 Q1 法說會逐字稿

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

(Operator Instructions)

Please note: This event is being recorded.

I would now like to turn the conference over to Mr. Chris Stavros.

Mr. Stavros, please begin.

Thank you, Emily.

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

On the call with us this morning from Houston are: Steve Chazen, Oxy's President and Chief Executive Officer; Vicki Hollub, Executive Vice President and Head of Oxy's US Oil and Gas Operations; Cynthia Walker, our Chief Financial Officer; Willie Chiang, Oxy's Executive Vice President of Operations, and our Head of our Midstream Business; Bill Albrecht, President of Oxy's Oil and Gas in the Americas; and Sandy Lowe, President of our International Oil and Gas Operations.

In just a moment, I will turn the call over to our CFO, Cynthia Walker, who will review our financial and operating results for the first quarter, and also provide some guidance for the current quarter.

Our CEO, Steve Chazen, will then provide an update on the progress of our strategic initiatives, and also some comments on the composition of the remaining Oxy, after the separation of our California business.

Vicki Hollub will then conclude the call with 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 from those expressed or implied in these statements and our filings.

Our first-quarter 2014 earnings press release, the Investor Relations supplemental schedules, 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 Cynthia Walker.

Cynthia, please go ahead.

Thank you, Chris, and good morning, everyone.

My comments will reference several slides in the conference call materials that are available on our website.

In the first quarter, we're off to a strong start in our domestic oil growth strategy.

Domestic oil production was 274,000 barrels per day, an increase of 4,000 barrels from the fourth quarter of 2013.

Overall production was 745,000 BOE per day.

We had core income of $1.4 billion, resulting in diluted earnings per share of $1.75 for the first quarter.

This is an improvement over both the prior and year-ago quarters.

We generated $2.9 billion of cash flow from operations before changes in working capital, and repurchased 10.5 million shares, ending the quarter with $2.3 billion of cash on our balance sheet.

Now I will discuss the segment performance for the oil and gas business, and begin with earnings on slide 3. Oil and gas core earnings for the first quarter of 2014 were $2.1 billion.

As you can see, this was essentially flat with the fourth quarter of 2013, and an increase of almost $200 million over the first quarter of 2013.

On a sequential quarter-over-quarter basis, we saw improvements from higher domestic realized prices on all of our oil and gas products, and higher sales volumes in Colombia, which were offset by lower sales volumes in Iraq.

In Colombia, while we recouped liftings in January, which had slipped from the fourth quarter of 2013, insurgent activity continues to challenge both our production and liftings in our Llanos Norte fields.

Production from the fields was shut in, in April; however, now, pipeline repair work has begun and we look forward to have normal operations in May.

In Iraq, operations were as expected, although liftings continue to be lumpy.

We had no liftings in Iraq in the first quarter.

Turning to slide 4, total production from the current quarter was 745,000 BOE per day, a decrease in daily BOE production of 5,000 from the fourth quarter and 18,000 from the year-ago quarter.

On a sequential quarterly basis, these results reflect domestic growth of 4,000 BOE per day, mainly in the Permian Basin, offset by lower production in California.

The Permian Basin improvement reflected recovery from fourth-quarter severe Winter weather and new production from our drilling program.

California production was essentially flat, excluding one-time benefits, which positively impacted the fourth quarter of last year.

In MENA, production was 9,000 BOE per day lower, primarily due to a scheduled plant turnaround in Dolphin, and the remainder in Bahrain due to contract terms.

If you turn to slide 5, I will discuss our domestic production in more detail.

Focusing on our commodity composition, on a sequential quarterly basis, we saw oil production grow 4,000 barrels per day, with the increase coming from all of our business units.

NGL production increased 2,000 barrels per day, almost entirely in the Permian.

Natural gas volumes were 10 million cubic feet per day lower, or about 2,000 BOE per day, with the decline coming from California, partially offset by higher production in the Permian and Mid-Continent.

Turning to slide 6, our oil and gas operating cash margins improved by $0.20 per BOE on a sequential quarterly basis.

Our first quarter of 2014 worldwide realized oil prices were essentially flat compared to the fourth quarter of 2013, although domestic realized oil prices improved slightly, despite widening differentials in the Permian Basin.

We also realized higher NGL prices domestically, due to seasonal factors, and experienced a 37% increase in natural gas prices, reflecting an improvement in the benchmark.

Oil and gas production costs were $14.33 per barrel in the first quarter of 2014, compared to $14.13 per barrel in the fourth quarter of 2013.

Domestic operating expenses were higher in the first quarter compared to the fourth quarter, due to higher energy, and CO2 and steam-injectant, costs.

Controllable costs were essentially flat on a sequential quarterly basis.

MENA production costs decreased in the first quarter, due to underliftings in Iraq, which have higher operating costs.

First-quarter exploration expense was $55 million, and we expect second-quarter exploration expense to be about $80 million.

Turning to chemical segment core earnings on slide 7, you'll see first-quarter earnings of $136 million.

This was $8 million higher than the fourth quarter, and exceeded our expectations, primarily driven by volume improvements across most products in preparation for a strong Spring demand.

This improvement was, in part, offset by the run-up in natural gas costs, due to the extreme Winter cold.

We expect second-quarter 2014 earnings to be about $130 million.

A seasonal uptick in demand in construction and agricultural markets is anticipated, although profitability will be somewhat negatively impacted by a number of routine, planned outages by both OxyChem and its customers.

On slide 8 is a summary of Midstream segment earnings.

You will see they were $170 million for the first quarter of 2014, compared to $68 million in the fourth quarter and $215 million in the first quarter of 2013.

The 2014 sequential quarterly increase in earnings resulted mainly from higher marketing and trading performance, driven by commodity price improvements during the quarter; higher income in the gas processing businesses, which were negatively impacted by the plant turnarounds in the fourth quarter of 2013; partially offset by lower pipeline earnings, which included a plant turnaround in Dolphin.

The worldwide effective tax rate on core income was 40% for the first quarter of 2014, and we expect our combined worldwide tax rate in the second quarter of 2014 to remain at about the 40% rate.

Slide 9 summarizes our cash flow for the quarter.

In the first three months of 2014, we generated $2.9 billion of cash flow from operations before changes in working capital.

Working capital changes decreased our cash flow from operations by about $240 million, to $2.7 billion.

Capital expenditures for the first quarter of 2014 were $2.2 billion, net of partner contributions; and after paying dividends of $515 million, buying back stock of $945 million, and other net flows, our cash balance was $2.3 billion at March 31.

Our debt-to-capitalization ratio was 14% at the end of the quarter.

Our 2014 annualized return on equity was 13%, and return on capital employed was around 11%.

Lastly, I will turn to our guidance for the second quarter.

On April 30, we closed the sale of our Hugoton assets for $1.3 billion.

In the first quarter, the Hugoton operations produced 18,000 BOE per day, invested $17 million in capital, and contributed $46 million to our pre-tax segment earnings.

For the full year, our previous domestic and capital expenditure guidance is unchanged, adjusting for Hugoton.

In the second quarter, excluding the Hugoton business, we expect domestic production will increase between 6,000 and 8,000 BOE per day on a sequential quarterly basis.

We expect oil production to grow between 7,000 and 9,000 barrels per day, or approximately 3%.

NGL volumes will be roughly flat with the first-quarter levels, and a modest decline in natural gas production resulting from continued limited drilling.

Internationally, at current prices, and excluding Colombia and Libya, we expect total production to increase around 10,000 BOE per day in the second quarter, primarily from the recovery of the Dolphin plant turnaround and activity in Oman.

We expect Middle East liftings to also increase about 10,000 BOE per day in the second quarter, primarily as a result of our production increases in Dolphin and Oman.

I will now turn the call over to Steve Chazen, who will provide an update on our strategic initiatives.

Thank you, Cynthia.

I want to focus on two topics this morning: our progress to date in executing strategic initiatives we announced earlier; what our business will look like after the completion of some of these initiatives.

Starting with our progress to date, we closed the sale of our Hugoton assets for pre-tax proceeds of just over $1.3 billion.

We sold, in the fourth quarter of last year, about 25% of our interest in Plains Pipeline for pre-tax proceeds of $1.4 billion.

Our remaining interest in Plains is worth over $4 billion at current market prices.

We continue to explore our options to monetize this remaining interest in a financially efficient manner, once the restrictions on market transactions lapse.

We are continuing to explore strategic alternatives for our Piceance assets, and decided to keep our interest in the Williston Basin, as they are currently more valuable to us relative to their value in the cash asset sale market.

We continue to make progress on our discussions with our partners in the Middle East for the sale of a portion of our interests in the region.

The separation of our California business from the rest of the Company, which will be in the form of a distribution of at least 80% of the Company's California stock to Oxy shareholders, is on track, and the necessary work is rapidly moving forward.

We expect to file an initial Form 10 in June, and announce the California management team in the third quarter.

Completion of the separation of the California business is expected to occur in the fourth quarter of this year.

We have repurchased more than 20 million of the Company's shares since the announcement of our strategic initiative in the fourth quarter of 2013, of which 10.5 million shares were purchased in the first quarter of 2014.

About 26.5 million shares remain in our current repurchase program, which we plan to complete with the proceeds from the Hugoton sale and excess balance-sheet cash.

Now discussing what the Business will look like going forward: As a stand-alone company, which will be called California Resources Corporation, we expect our California operations to be an exciting growth-oriented business, with a large resource base and self-sufficient cash flow.

This business will be a pure California resource company that will be able to spend virtually all its cash flow to grow its production, reserves and earnings.

Currently, the California business spends about half of its capital on conventional water and steam floods, and the other half on unconventional and other development projects.

The business is expected to initially increase its high-margin, high-return conventional spending, such as water and steam flood investments, to grow its production by 5% to 8%, with double-digit oil growth.

As the floods reach their steady state in the near term, they are expected to generate significantly more cash flow, which the company expects to use to increase the amount and share of its capital spent on unconventional programs to grow its production higher rates on a sustainable basis.

The business will be well positioned to accomplish this strategy, as it's generated operating cash flow before capital spending of $2.6 billion in 2013.

The capital spend in 2013 was $1.7 billion, and we expect to spend about $2.1 billion this year.

We expect the California company will have around $5 billion of debt, proceeds from which will be distributed to Oxy to be used primarily to repurchase shares.

After completion of the strategic initiatives, Oxy's most important assets will consist of a significant and leading position in the Permian Basin, rounded out by the Al Hosn project, Dolphin, and a smaller business in the rest of MENA; our operations in Colombia, our midstream and chemical business, and other domestic oil and gas operations.

Each of these businesses supports our ability to grow our dividends for our shareholders.

Further, one of Oxy's objectives will be to grow earnings and cash flow per share, and these businesses have already identified opportunities to do so.

Permian resources is the cornerstone growth operation for the domestic business.

Our substantial acreage position in the Permian gives us significant resource development potential.

We have used our knowledge of the geology of the area and our experience to gradually shift our program towards horizontal drilling in an efficient manner.

We have already made significant progress in this process, and are on track to execute the shift as planned.

We are starting to see the positive results of our horizontal drilling program, expect the resources business to grow production rapidly, similar to what some other operators in the basin have been able to achieve.

We believe this business could increase its production by 13% to 16% this year, and in excess of 20% going forward.

The EOR business in the Permian Basin, which is primarily CO2 assets, along with the rest of the Company's businesses, continue to be significant free cash flow generators.

In 2013, excluding the California assets, Oxy generated operating cash flow of $10.3 billion, while spending $7.2 billion on capital expenditures.

2013 capital included $950 million spent for Al Hosn, and $370 million for the combination of BridgeTex pipeline and the Johnsonville chlor-alkali plant.

We expect all three major projects to come online at various times in 2014, freeing up significant amounts of capital, while starting to contribute to cash flow generation.

Assuming current market conditions and similar product prices, once fully operational, these three assets should generate at least $700 million in annual operating cash flow.

We expect this higher level of cash flow, coupled with significant reductions in capital needs for long lead-time projects, will more than offset the loss of cash flow generated by the California assets and provide a significant boost to our free cash flow going forward.

Our chemical and midstream business will also continue to be meaningful cash flow providers in the future.

The strong cash generation, and combined with fewer shares outstanding, will enable us to continue to increase our dividend from the current rate, while having sufficient funding to increase our investments in domestic growth assets.

We also expect Oxy's remaining businesses to deliver higher returns going forward, as a result of our investments, strategic initiatives and assuming similar commodity prices.

We expect our improved capital efficiency and operating cost structure to start up the Al Hosn, BridgeTex, and new Johnsonville plant, along with the separation of the California business, will provide a natural uplift to our return on capital employed.

In addition, we continue to execute our strategic initiatives and use proceeds from [expected] transactions, such as the sale of Hugoton and the monetization of the remaining portion of Plains, to repurchase our stock, which will be able to further increase our ROCE going forward.

Our ROCE was 12.2% in 2013, and we expect it to rise to around 15% as we exit 2015.

We have already repurchased more than 20 million of the Company's shares since the end of the third quarter of 2013.

We expect that we will be able to further reduce our share count by 40 to 50 million shares through dividends from the California separation, and by around 25 million shares through the monetization of our remaining interest in the Plains pipeline.

Coupled with the buyback of 26.5 million shares in our current repurchase program, we should be able to reduce our current share count by 90 to 100 million shares, or about 12% of our currently outstanding shares.

These amounts do not include the opportunity to repurchase additional shares through a sale of a portion of our interests in the Middle East, or share reductions from the exchange of any remaining portion of our interest in the California business, but they do reflect a modest amount of debt reduction.

We are excited about the value propositions of both our California and remaining Oxy businesses, with our differentiated but focused business models, positioning both companies to maximize shareholder value.

Now I will turn the call over to Vicki Hollub to update you on our Permian activities.

Thank you, Steve.

This morning, I will update you on the activities to date in our Permian resource business, where we were off to a good start in 2014.

In the first quarter, Permian resources produced 67,000 barrels of oil equivalent per day, an increase of 5% over the fourth quarter of 2013.

Capital expenditures were $328 million, with approximately 75% spent on drilling and completing Company-operated wells.

We averaged 22 rigs during the quarter, of which 15 were horizontal rigs.

This allowed us to drill 67 wells, including 25 horizontals.

About three-fourths of the 25 horizontals are currently on production.

As I indicated in the last call, we have two main goals for our Permian resources business in 2014: first, continue evaluating the potential across our full acreage position; and second, pilot development strategies to optimize their ultimate returns.

Today, I will focus on the progress we made in areas where we are targeting the Wolfcamp shale and one where we are targeting primarily the Bone Spring.

Those areas are South Curtis Ranch and Dora Roberts Ranch in the Midland Basin, Barilla Draw in the Texas Delaware Basin, and southeast New Mexico.

These make up the core of our horizontal program thus far.

Our Wolfcamp activity in the Midland Basin is focused in two operating areas, South Curtis Ranch and Dora Roberts Ranch, where we have identified about 800 drilling locations.

In the Wolfcamp, we brought 12 wells on production during the quarter, and now have a total of 18 producing wells.

All but one of these wells are completed in the Wolfcamp B; the others completed in the Wolfcamp A.

The initial production rates are averaging around 750 BOE per day.

While this is a good start, we believe we can improve on this result by increasing the lateral lengths of our wells and improving the efficiency of our fracs.

The wells drilled thus far have an average lateral length of around 6,000 feet.

We are piloting increased lateral lengths up to 10,000 feet.

In addition, we have transitioned from gel fracs to slick water fracs, which has improved well performance, and we've adjusted our cluster spacing from 60 feet to 95 feet for this area.

We're also evaluating lift alternatives.

To date, we have primarily used gas lift and ESPs.

ESPs averaged 1,020 BOE per day initial production rate, versus 680 per day for the other wells, which are flowing or on gas lift.

The rate benefit of the ESPs may prove to be economically equivalent to gas lift, but we are closely monitoring the potential impact to the reservoir.

Average drill time for the horizontals was 27 days per well, and total costs for drilling and completion has been averaging around $6.5 million per well.

With these changes to the completions that I mentioned, initially costs may increase slightly, but we expect to bring them down as we further progress the development program.

While the program is young and we have more to learn, we continue to be encouraged by the results that we see.

We are currently drilling our first horizontal well in [Maybe] Ranch, where we hold over 9,000 acres.

This is an area that we expect to have similar potential to South Curtis Ranch, which is of similar size.

We are also drilling two horizontal Spraberry wells in South Curtis Ranch, and expect to bring them on production by the end of the second quarter.

Shifting to the Wolfcamp and the Delaware Basin in Texas, we brought our first five wells on to production during the quarter, and the results have been very strong.

Two of the wells were completed in Wolfcamp B, one in the Wolfcamp A, and two in the Wolfcamp C. The initial production rate for the Wolfcamp A and B wells averaged 1,150 BOE per day.

And these wells are located in our Barilla Draw area in Reeves County.

Given the size of this development opportunity, we are investing early in infrastructure.

Our exploitation team and the Permian resources business unit have worked together to design and construct the Barillla Draw water distribution project, which will provide an economic alternative to trucking water to support drilling and completion operations in Barilla Draw and the surrounding Oxy-operated leases, as we move into full field development mode.

The project plan includes over 50 miles of pipeline and 25 water ponds, networked together, to allow Oxy to aggregate and transfer the water required to execute all operations, including zipper fracs, by expediting water delivery to all well locations.

With the ability to incorporate a more efficient completion strategy, we can reduce time to market, decrease cost, and accelerate to move to pad drilling operations.

This project is expected to result in a 4% capital cost savings per well, through reduction of water handling costs by more than 75%; and it will become the standard water handling template for future horizontal well developments.

In the Delaware Basin, drilling and completion costs are averaging close to $8.5 million per well, due to the greater depth, pressure, and hole instability associated with drilling the Wolfcamp C. Recently, managed pressure drilling was successfully utilized to mitigate the hole problems.

This technique will be evaluated for broader deployment into other areas.

We appreciate the efforts of our Permian resources business unit and the exploitation team, as they have successfully ramped up our activity while continuing to efficiently manage operations and costs.

In addition, they have identified several key ways to improve the performance of our wells in all areas, beginning with a switch from gel fracs to slick water fracs, which, as I mentioned, has already begun in South Curtis Ranch.

We are transitioning to slick water fracs in other areas, as well.

In addition, we recognize that the appropriate cluster spacing is dependent on the reservoir characteristics for each area, and we are evaluating and then optimizing in all areas.

Just as we have done in South Curtis Ranch, we are also continuing to evaluate the lateral lengths of our wells in other areas, and expect to find opportunities to continue to increase lengths in multiple areas.

We expect these initiatives to have a positive impact on the performance of our future wells across Permian.

Our most mature horizontal program is in southeast New Mexico, where we began horizontal drilling at the end of 2012.

We put 7 new wells on production in the quarter, and now have a total of 26 horizontal wells on production in this area.

Of those, 17 are in Bone Spring intervals, and the other 9 are Brushy Canyon wells.

The first and second Bone Spring wells averaged an initial production rate of 700 BOE per day.

Three of the Brushy Canyon wells were put on ESP, with average initial production rates of 1,100 BOE per day, and four others averaged 300 BOE per day.

Average drill time for the horizontal wells was 30 days per well, and total cost for drilling and completion averaged $5.6 million.

Looking forward, we expect to average 26 rigs during the second quarter, and will peak at 27 rigs in the third quarter, of which 18 will be horizontal.

For the full year, we remain on track to spend $1.6 billion and drill approximately 340 wells.

We continue to expect Permian resources to grow its total production for the year by 13% to 16%.

As you can tell, there are a lot of exciting things happening in the Permian resources business, and the teams are working incredibly hard to increase our knowledge to move us faster up the learning curve.

I will now turn the call back to Chris Stavros.

Thank you, Vicki.

Emily, we're now ready to poll for questions.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

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

Please go ahead.

Thanks.

Good morning, everybody.

Steve, I wonder if I could take a couple, please.

First of all, thanks for all the disclosure on the share buyback plan.

But there is obviously a fairly large omission from the discussion, which is MENA and the potential proceeds from MENA.

So I'm wondering if you can give us an update as to where that process stands and how that may impact the buyback plan, also.

And then I've got a follow-up on the Permian, please.

Yes.

I think we continue to make progress in it from both parties that are -- or both groups of parties, if you want to think of it that way, that are involved.

And rather than speculate on the amount, we'll just say that that would increase, perhaps materially, the share buyback program.

But I think it's not helpful, at this point, with the parties, to speculate on what the amount might be.

I understand.

Could you maybe help us a little bit with the time line?

Because obviously, one of the things that we've talked about backwards and forwards is whether or not you would be prepared to sort of pre-fund the debt for California and buy back shares, or are you going to wait until that process is complete?

So when you consider Plains as well, is this an 18-month kind of time line we're talking about for the buyback, or would you be inclined to accelerate it?

We'll just see how the stock responds.

If we see an opportunity, we could accelerate it.

If not, we'll wait.

But you should expect continued reduction in the share count through the rest of this year, and into next year.

Okay.

My follow-up is really kind of related, I guess, because you've given us an idea of what the free cash flow could look like for the residual company.

And obviously, it would seem that even with this step-up in spending in the Permian, you're still going to have substantial free cash available, especially from the CO2 business.

So I guess what I'm thinking is, what are your plans on a go-forward basis?

The Permian is going to grow, but would you expect that growth per share would be the metric and that buybacks become a more ratable piece, or are acquisitions in the Permian something that's still appealing to you over time?

And I'll leave it there.

Thanks.

On the acquisitions right now, it's really not accretive.

Generally speaking, the public markets are way ahead of the cash markets.

And the public markets could be right, and the cash markets wrong.

But right now, I don't find acquisitions to be particularly interesting and we're not doing anything that's dilutive.

So I think as far as acquisitions, I think that's unlikely.

As we look forward, in our cash flow, we expect our earnings per share, starting with the current levels, to continue to grow.

We hope it will grow this year, and we expect it to grow going forward.

We expect our cash flow per share, if you want to use that metric, to continue to grow and we expect the dividends to grow.

Share repurchase, I think for the next several years, I doubt if the Company will need to do a large scale, any kind of major acquisitions.

There's always little pieces to be picked up.

But I think the Company will continue to use its cash flow to grow dividends, where it's predictable cash flow growth, and to repurchase shares, where it's less predictable.

Some modest debt reduction to go with the smaller scale of business, but that's -- you know, I think what people should expect.

They should expect better earnings -- better returns on invested capital.

They should expect some continued reduction in the share count, at a modest, more modest rate, after this process is done, and growing dividends.

I appreciate that.

Thanks, Steve.

Our next question is from Paul Sankey of Wolfe Research.

Please go ahead.

Good morning, everyone.

Thanks for making the effort to get on the call, all of you.

Steve, could you just talk a little bit more about the decision to pull the Bakken sale, the process around that, and what your plans are for that business going forward?

Thanks.

Yes.

We're not doing wealth destructive divestitures.

So if we got a price that was sort of comparable the way we trade, I think that's one thing.

But the cash market is just simply not that strong right now.

And so our plan -- it makes around 20,000 a day of production.

We've restarted our development program.

And so I think it will grow modestly over the next year or two.

We don't have -- and we'll just see what the markets give us going forward.

I'm sort of -- we could either grow it or we could divest.

But right now, the cash divest just doesn't get the kind of proceeds that we think are intrinsic in the business.

Could you remind us why you wanted to sell it?

The scale.

It's 20,000 a day.

The scale was below what we've been wanting.

We'd probably need a 40,000 or 50,000 a day business.

The business has actually done better, on an operational perspective, over the last year, than it had done historically.

So I think it's suboptimal scale.

Perhaps at some point in the future, there might be an opportunity to merge it in with somebody else.

But right now, I think we'll just keep it there.

It's not doing any -- it may be doing some modest good, and not doing any harm right now.

I guess the obvious follow-up is that if you're not seeing the right prices to sell stuff, wouldn't you want to buy stuff there to get up your scale?

If there was stuff at the same price.

The market is not -- it's not a robust market.

And so the companies trade for much more than, relative basis, than people offered us for the asset.

So what they were trying to do is do accretive acquisitions for their company, I'm sure.

But with multiple differences.

Just to finish up off on that, and that will be it for me.

On slide 11, just to finish off on that particular paragraph, could you talk a little bit more about the Piceance, as well.

Because this says, explore strategic alternatives.

I wondered what those were.

And I'll leave it there.

Thank you.

On the Piceance, we're in discussions with a private party to create a joint venture.

They have a fair amount of interests in the Piceance.

We have a fair amount.

The current plan is to put them together, run them as a private business for a while; and then at some point in the future, they'd have enough scale to go public.

Thank you.

Our next question is from Leo Mariani of RBC.

Please go ahead.

I just wanted to follow up a little bit on some of these asset sales.

I appreciate some of the color here.

But could you give us a little bit more color, potentially, on timing of the rest of the Plains GP, when you think that might exit the portfolio?

And then I think there were maybe some other small US non core assets, wasn't sure if you guys were still selling some other little things here or that may be off the table, as well?

There's always small things for sale, but nothing that's going to move the needle a lot.

On Plains, I think it expires at the end of the year -- towards the end of the year -- and we'll be looking to see what we can do early next year.

Okay.

And I guess just in terms of the Permian, you guys are creeping up the horizontal rig count, 17 now, it's going to 18, I think you said, another quarter or two.

Can you just give us maybe a better sense of where maybe that could get you over the next couple of years?

Do you have a multi-year rig ramp plans on the horizontal side in the Permian?

Any color around that would be appreciated.

Vicki would be glad to talk about that.

We expect to double our rig count from this year, in two years, to double.

So going from the 23 peak that we'll have this year to possibly 46 in 2016.

For horizontal rigs, this year, as you know, as you just said, in Q3, we'll be going to 18 horizontal rigs and expect to end the year, this year, with about 21 horizontal rigs.

We'll increase that from the end of the year, 21, going up toward 2016.

We don't have an exact number as to what the horizontal rig count will be of that total, but we expect it to be about double.

Okay.

That's helpful.

And I guess you guys specifically highlighted this Barilla Draw acreage here in your slide.

Just want to get a sense of how much acreage that is in total.

And maybe you could just talk a little bit more about the areas of the Midland that you think are the most prospective, in terms of maybe the total acreage size there.

In the Texas Delaware, I can talk about basically what we expect our well potential to be.

It's going to be, in that area, we expect to drill over 1,000 Wolfcamp wells, depending on the productivity of some of the benches that we have yet to test.

So this is -- the over 1,000 is based on the benches that we feel pretty comfortable with today.

That would be in that Barilla Draw area, plus the surrounding acreage.

So that would be for all of Texas Delaware.

And I guess just also, a similar question on the Midland.

You highlighted a number of small acreage parcels here, in largely Martland, Midland and some in [Echter].

Just wanted to get a sense if there is an acreage number that you guys could throw out there in the Midland, in terms of what you think is the high grade stuff that's most prospective for horizontal drilling.

In the Midland basin, we expect that the acreage that we have listed there for the three areas that we show, we expect our prospective acreage to be about double that for the Midland Basin, from what we know today, from the appraisal work that we're doing, currently doing.

Okay.

Thanks.

That's helpful.

Our next question is from Roger Read of Wells Fargo.

Please go ahead.

Good morning.

Good morning.

A lot of this stuff's been hit.

If we could talk a little bit about the share repurchase pace again.

You've mentioned several times where there's flexibility in terms of the pace of share repos.

Maybe give us an idea, assuming California goes out on the schedule you expect, the way to think about it.

Is it stock price driven?

Is it cash flow on hand?

Is it combination of the two?

And getting back to the earlier question about, would you be willing to put the balance sheet to work here?

It's stock price driven.

Just that simple?

That simple.

Okay.

Well, that's helpful.

And then in the Permian, obviously understand everything going on in the spending front here.

Could you talk a little bit about the infrastructure you need?

We've heard from various sources that some of the challenges are more in the gathering systems than in the trunk line systems, kind of how you're addressing that issue?

Maybe we'll get Willie to talk about -- we're a large gatherer in the basin.

Maybe we could talk a little bit about our gathering system in the Permian.

Sure.

We really haven't had too much problems in getting the gathering done.

The big challenge, as you've seen, is really the trunk lines, which we think is going to resolve itself here with the start-up of our BridgeTex pipeline later this quarter, early third quarter.

So from the infrastructure piece, on gathering.

Okay.

I guess one of the questions along that line is, if you're having issues with crude versus condensate versus gas handling, and then maybe what your spending will do on that front, and are we going up in concert with the rig count, or something more or less?

We may be looking at some more gas processing facilities.

But on the natural gas side, we feel it's adequate.

We've got a big gathering system, so we'll probably have more flexibility maybe than somebody who doesn't have their own gathering system.

Willie, how many miles of gathering system do you have, roughly?

We've got close to 3,000 miles of pipe in the Permian.

Permian.

So we're a big gatherer, not just of our own, but other people's crude.

So we may have a little more flexibility than maybe some of the smaller producers.

Okay.

Thank you.

Our next question is from Sven Del Pozzo of IHS.

Please go ahead.

Hello.

Wanted to -- what's your take on macro forecast for California gas?

Because we're -- and I know you guys have those fields you bought from Beneco Rosetta, so you must be one of the biggest, potentially, fields for gas -- and also those older discoveries you had, I don't know, six, seven years ago that were gas and condensate, that I'm not sure whether you got around to developing them, because gas prices weren't strong enough.

So what's your take on the local gas market in California and how you might use your gas assets to take advantage of that?

Right now, we have a lot of gas potential in the state.

We could increase our gas production substantially.

Right now, the oil drilling has got significantly better margins and significantly better returns.

If that changes, gas prices go up some more, some of our stuff, I'm sure, is economic in the $4.00, $4.50 area, but just not as economic as $100 oil.

So I think right now, we'll keep our gas drilling modest in California.

But clearly, when the California company is separate, they could take a different view of this and maybe have somewhat different return standards than we do.

All right.

So then the gas production drop we saw in California sequentially from the fourth quarter to the first quarter, is that -- what kind of a decline is that?

Could I consider it a base decline?

Or you said it's going to flatten out now in the second quarter.

So I'm just trying to get a feel of how those -- what the legacy decline rate of those gas assets might be, if you stop drilling.

We pretty much stopped.

So Vicki can answer the rest of it.

Some of the decline of our gas assets was in excess of 25%.

And that's why we made the switch to move to more toward some of our conventional EOR projects and water floods.

We've had some gas declines that were actually greater than 30%, as well.

So we're trying to lower that decline.

And we've now been able to lower the decline of Elk Hills over the past few years by switching more toward our heavier liquids drilling and development.

Well, thank you.

And one last question.

When you mentioned the Permian unit, if I'm correct in repeating what you said, I think you said you spent about $1.6 billion to drill and complete about 340 wells.

Was that a gross number?

That's in 2014.

Was that a gross number?

And if so, could we get a net number?

Currently, the number of wells is a gross number, and the capital is a net number.

We don't quite have here in front of us the net number on the wells.

And the gross number doesn't include the third party wells.

Right.

Those are gross operated --

Yes.

Those are gross operated.

And the capital is sort of a mix.

But it doesn't include the non-operated wells, because we don't know what that will be.

Okay.

All right.

Thank you.

Our next question is from Ed Westlake of Credit Suisse.

Please go ahead.

Good morning.

Just wanted to get a little bit more color on how you see the Permian developing.

You've given us some extra disclosure on the Midlands.

You've got 40,000 acres there, plus you say you could double that.

So 80,000.

You've given us 1,000 locations as the number for Barilla Draw, and then you've got this large acreage position in New Mexico.

I guess the concern people have is that as you accelerate the rig counts, you guys don't have as much inventory as some of the, say, pure plays in the region.

So I'm just trying to get a sense of where, apart from what you've disclosed today, we should be thinking would be the growth area in your existing organic portfolio?

Vicki can answer that, I think, better than I can.

But we've disclosed how many acres we have that's prospective, and we just highlighted the areas in this call that are going to affect the production over the next two or three quarters.

It wasn't intended as what might be there for the next 20 years.

But I think Vicki can probably answer better than I can.

Yes, we have close to 2 million in prospective acres in our Permian resources business unit.

And currently, we've identified over 4,400 well locations to drill.

So we're not short on inventory yet, because we're still in the process of evaluating some of the other benches, too.

So expect the well location number to go up with time.

And I guess that, just to be clear again, that 4,400 or 4,500, that's the net locations operated, or what's the definition of that?

So we can compare apples with apples.

That's the gross operated well locations.

Okay.

So that would compare with the 340 to give about a 13-year inventory.

Is that correct?

Yes, that's correct.

And so I guess I'm trying to think about what's the upside to that, in terms of what percentage of your acreage you have drilled out, as you think about that 4,500 acres?

I think the important thing to remember for us is that with wells, horizontal wells we've drilled to date, we've really only drilled only about 1% of our potential.

So if you look at these kind of plays, normally that well count goes up significantly over time, as you can get to the other benches to appraise those.

So I think our estimate right now is conservative, based on what we have available to evaluate, and expect that number to continue to go up as we learn more.

Okay.

Great.

And then a specific question on Barilla Draw.

You've got 88% liquids.

Just a sense of how much of that is NGLs and how much of that is condensates.

Obviously, the IPs are looking good, but just trying to get a sense of the liquid mix.

Thank you.

72% of that is oil.

And do you know the API of the oil?

Is it --

I think it's in the 30 to 35 range.

Okay.

Good.

Thank you very much.

Our next question is from Pavel Molchanov of Raymond James.

Please go ahead.

Thanks for taking the question.

Steve, we saw in the last several months the city of Carson, LA County, a few other jurisdictions in California, have been putting up proposals, anti-fracking, some cases anti-drilling --

There's no LA County.

It's the city of Los Angeles.

City of Los Angeles.

So your thoughts on the trend?

Is there a trend?

Well, I think a fair way to describe it is that it's basically supposed to be regulated by the state of California.

That's the way the laws are set up in California.

Not regulated by every town.

To the extent that the towns don't want us there, we won't be there.

We've got lots of acreage in California.

There's lots of counties and towns that would like us there, want the jobs.

Some of these places that don't want us have very high unemployment rates.

And if they don't want us there, it's just fine.

So far, these areas are not significant portions of our total position in California.

They're some relatively small positions that are being stirred up by people who don't like oil and gas.

And so I think that when the California company is up and running, one of their major tasks will be to -- and major focus will be on dealing with the political issues in California.

But noise is sort of what California produces.

The political guy wants to talk about fracking or something, doesn't necessarily know anything about it.

And just for the completeness, I think the Beverly Hills City Council voted to bar fracking within the borders of the city of Beverly Hills.

Now traditionally, I thought I misunderstood what they were saying, and then they were trying to outlaw their most important export product.

But actually, I don't -- no wells have ever been proposed to be fracked, no wells are ever-- I think there's one field there that's been there for about 50 years.

These are just politicians trying to make some sort of statement.

Maybe the people in Beverly Hills should park their Rolls Royces and drive bicycles going forward.

Indeed.

Just one more quick one on California.

When you refer to the --

You can see why I'm not going to be part of a California company.

Understood.

When you refer to the $5 billion of funded debt in the spin co, is that effectively going to be structured as a dividend, $5 billion dividend to the Behrend?

Yes.

Okay.

Appreciate it.

Thank you.

Our next question is from John Herrlin of Societe Generale.

Please go ahead.

Yes, thanks.

Some quick ones.

How much, in the Permian, how much incremental costs are the ESPs for you?

Obviously, I'm not going to answer that.

Vicki can answer it.

I'm going to -- just to be honest, I'll have to take a guess on this.

I haven't looked specifically at that number recently.

But I believe it would be about a $35,000 to $40,000 incremental over the gas lift.

It could be a little bit more than that.

Okay.

Steve, when you were in New York, you said that you thought you were you a top quartile in terms of your drilling and completion work in the unconventional Permian.

Is that improving at all with the subsequent wells drilled?

I think so.

But I think we'll stay with the top quartile for now.

We've got more to do.

I think that things are getting better.

Our overall costs -- we didn't say it actually -- our overall costs as a company are 9% better than the comparable wells drilled from last year, so far this year.

So I think we're getting better.

But we've still got more to do, more costs to be saved, better completion techniques.

I think Vicki's been pretty forthright about what she wants to accomplish in that.

So I think there's more to do, which is good.

It will never -- the continuous improvement will never end.

Great.

Last one for me is on the dividend for Oxy remain co, are you going to hold it flat?

Will it go down a little bit for the spin co?

No, it will go up.

It will go up.

Okay.

The dividends -- the way this thing is set up, is the dividends from the post-California company, the company will be able to increase its dividends at a reasonable pace going forward.

And the goal is not to have it reduce its dividend or hold it flat, like some others have done.

People should expect the same kind of increases.

The percentages may be different, but the same kind of increases that they've enjoyed in the past.

Okay.

Last one for me is on Phibro.

Are you going to monetize that, or what's the story, if you can mention it?

Yes.

They're out -- if you'd like to buy it, I think it's available.

So they're out talking to investors who want to do the credit support for Phibro.

But in any case, their book is declining over the next couple quarters.

Okay.

Thank you.

Thanks.

This concludes our question-and-answer session.

I'd like to turn the conference back over to Chris Stavros for any closing remarks.

Thanks for joining us on the call today.

And please give us a call in New York if you have any further question.

Thanks.

Thanks.

The conference is now concluded.

Thank you for attending today's presentation.

You may now disconnect.