Good afternoon. My name is Christy, and I will be your conference operator today. At this time, I would like to welcome everyone to Occidental Petroleum's fourth quarter 2012 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. I would now like to turn the call over to Christopher Stavros. Please go ahead, sir.
Thank you, Christy. Good morning. Welcome everyone, and thank you for participating in Occidental Petroleum's fourth quarter and full year 2012 earnings conference call. Joining us on the call this morning from Los Angeles, we have quite a sizable group. Steve Chazen, Oxy's President, Chief Executive Officer, Cynthia Walker, Oxy's Executive Vice President and Chief Financial Officer, Bill Albrecht, President of Oxy's Oil and Gas Operation in the Americas, Sandy Lowe, President of our International Oil and Gas business, Willie Chiang, Executive Vice President of Operations and head of Oxy's Midstream businesses, our Executive Chair of the Board, Dr. Ray Irani. In just a moment, I will turn the call over to our CFO, Cynthia Walker, who will review our financial and operating results for last year's fourth quarter and full year 2012.
Steve Chazen will then follow with comments on our plan to improve our operational efficiencies and reduce our operating costs, a discussion of our capital program for this year, as well as our outlook for production, also some preliminary data of our year-end oil and gas reserves. As a reminder, today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause our actual results to differ from those expressed or implied in such statements and our filings. Our fourth quarter 2012 earnings press release, investor relations supplemental schedules, and conference call presentation slides, which refer to both Cynthia's and Steve's comments, 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. Good morning, everyone. Core income was $1.5 billion, or $1.83 per diluted share in the fourth quarter of 2012, compared with $1.6 billion or $2.02 per diluted share in the fourth quarter of 2011, $1.4 billion or $1.70 per diluted share in the third quarter of 2012. The improvement from the third quarter reflected the effect of higher liquids production, higher realized NGL and domestic gas prices, and reduced operating expenses in the oil and gas business. This partially offset by lower earnings in the midstream segment. In the fourth quarter, we recorded pre-tax charges of $1.8 billion, representing $1.1 billion after tax, or $1.41 per diluted share. Almost all of the charges were for impairments in the oil and gas Mid-Continent business units, over 90% of which were related to the natural gas properties that we acquired more than four years ago on average.
While the performance of the properties was generally as expected, natural gas prices have declined by approximately 50% since the acquisitions. In 2012, natural gas prices and NGL prices used for reserve calculations were significantly lower than prices used in 2011, resulting in declines in economically feasible reserves in these properties. In addition, despite the recent modest increase in natural gas prices, drilling in many of the gassy areas remains uneconomic. As a result, we continue to operate at minimal levels in these areas, as we've communicated previously. The charges related to the natural gas properties reflect the impairment of such properties to approximate fair value. Net income after the fourth quarter charge was $336 million or $0.42 per diluted share. I will now discuss the segment breakdown for results of the fourth quarter.
Oil and gas earnings for the fourth quarter of 2012, excluding the charge, were $2.3 billion, compared to $2 billion in the third quarter of 2012 and $2.5 billion in the fourth quarter of 2011. We delivered a quarter-over-quarter improvement despite a decline in WTI prices as a result of higher liquids production, higher realized NGL and domestic gas prices, importantly, lower operating expenses. Oil and gas production costs were $14.99 per barrel for the 12 months of 2012, compared with $12.84 per barrel for the full year 2011. Our fourth quarter production costs were $14.95 per barrel, which was $1.04 per barrel lower than the third quarter level. I would note that these reductions occurred during the course of the quarter, and our year-end exit rate on a per barrel basis was lower than the fourth quarter 2011 average and well below the fourth quarter 2012 level.
This gives us confidence in our operational efficiency efforts as we begin 2013. Steve will review the drivers of the performance and our expectations for 2013 in more detail. The fourth quarter 2012 total daily production on a BOE basis was 779,000 barrels, a new record set by the company. This was up 13,000 barrels per day from the third quarter of 2012 and up 4% from the fourth quarter of 2011. Our domestic production was 475,000 barrels per day, an increase of 6,000 barrels per day for the third quarter of 2012, and now the ninth consecutive quarter of domestic volume production. Production was 6% higher for the fourth quarter of 2011. Almost all of the net sequential quarterly increase in production came from oil in California and the Permian Basin.
Domestic gas production was down slightly from the third quarter, which was offset by higher liquids production resulting from higher yields from our new Elk Hills gas plant. Latin America volumes were 32,000 barrels per day, which was flat compared to the prior quarter and the same period in 2011. In the Middle East, production was 272,000 barrels per day, an increase of 7,000 barrels per day from the third quarter of 2012. Higher spending levels in Iraq and Oman resulted in 8,000 barrels per day higher production. Dolphin production, as with the last quarter, was lower due to the full cost recovery of pre-startup capital. Other factors affecting production sharing and similar contracts, including oil prices, did not significantly impact this quarter's production volumes compared to the fourth quarter of 2011 or the third quarter of 2012.
Further details regarding other country-specific production levels are available in the investor relations supplemental schedules that we provide. Fourth quarter realized prices were mixed for our products compared to the third quarter of the year. Our worldwide crude oil realized price was $96.19 per barrel, a slight decrease from the third quarter, while worldwide NGL prices were $45.08 per barrel, an increase of about 11%. Domestic natural gas prices were $3.09 per million cubic feet, an improvement of 25%. Fourth quarter 2012 realized prices were lower than the prior year fourth quarter prices for all of our products. On a year-over-year basis, price decreases were 3% for worldwide crude oil, 18% for worldwide NGLs, and 14% for domestic natural gas. Realized oil prices for the quarter represented 109% of the average WTI price and 87% of the average Brent price.
Realized NGL prices were 51% of the average WTI price, and realized domestic gas prices were 92% of the average NYMEX price. At current global prices, a $1 per barrel change in oil prices affects our quarterly earnings before income taxes by $37 million and $7 million for a $1 per barrel change in NGL prices. A change in domestic gas prices of $0.50 per million BTUs affects pre-tax earnings by about $30 million. These price change sensitivities include the impact of production sharing and similar contract volume changes. Taxes other than on income, which are generally related to product prices, were $2.39 per barrel for the full year of 2012, compared to $2.21 per barrel for the full year of 2011. Fourth quarter exploration expense was $82 million. We expect first quarter 2013 exploration expense to be about $90 million for seismic and drilling in our exploration programs.
Our fourth quarter DD&A rate was $14.47 per barrel, and we expect full year 2013 to be approximately $17 per barrel. In the Chemical segment, earnings for the fourth quarter of 2012 were $180 million, compared to $162 million in the third quarter of 2012 and $144 million for the fourth quarter of 2011. The sequential quarterly improvement reflected higher caustic soda and PVC prices, partially offset by higher energy and feedstocks. The year-over-year increase reflected higher export volumes for caustic soda and VCM and lower feedstock costs. For the first quarter of 2013, Chemical segment earnings are expected to be about $150 million. Typical weak seasonal demand, particularly in the construction and agricultural market segments, combined with the recent increases in ethylene and natural gas costs, may tighten margins in the first quarter.
Midstream segment earnings were $75 million for the fourth quarter of 2012, compared to $156 million in the third quarter of 2012 and $70 million in the fourth quarter of 2011. The 2012 sequential quarterly decrease in earnings was caused by lower marketing and trading, foreign pipeline, and power generation earnings. The worldwide effective tax rate on core income was 37% for the fourth quarter of 2012. The rate was lower than the prior quarter and our guidance, largely due to a higher portion of domestic income in the fourth quarter than foreign income. Our fourth quarter U.S. and foreign tax rates are included in the investor relations supplemental schedules. We expect our combined worldwide tax rate for the first quarter of 2013 to increase to about 40%. Now turning to cash flow.
In the 12 months of 2012, we generated $12.1 billion of cash flow from continuing operations before changes in working capital. Working capital changes reduced our full-year cash flow from operations approximately $800 million to $11.3 billion. Capital expenditures for the 12 months of 2012 were $10.2 billion, of which $2.5 billion was spent in the fourth quarter. The fourth quarter 2012 capital spend was approximately $100 million lower than the third quarter of 2012, driven by an approximately 12% reduction in oil and gas spending, partially offset by increases in the chemical and midstream segments. The higher capital at chemicals was related to the construction of a new membrane chlor-alkali plant in Tennessee, which is expected to be completed by the fourth quarter of 2013. Midstream capital was higher mainly due to the Al Hosn Gas project.
Total year capital expenditures by segment were 80% in oil and gas, 15% in midstream, and the remainder in chemicals. Acquisitions for the 12 months of 2012 were $2.5 billion, of which $1.3 billion was spent in the fourth quarter on domestic oil and gas properties. Financial activities, which included five quarterly dividends paid, stock buybacks, and a $1.74 billion borrowing earlier this year, resulted in a net use of cash of $850 million. These and other net cash flows resulted in a $1.6 billion cash balance at December 31st. During the year, we bought about 7.5 million of our own shares at a cost of approximately $580 million. Approximately 5 million of the shares were purchased in the fourth quarter at an average price of $76.15.
The weighted average basic shares outstanding for the 12 months of 2012 were 809.3 million, and the weighted average diluted shares outstanding were 810 million. The weighted average basic shares outstanding for the fourth quarter of 2012 were 807.1 million, and the weighted average diluted shares outstanding were 807.7 million. At the end of the year, we had approximately 805.5 million shares outstanding. Our debt-to-capitalization ratio was 16% at year-end. Finally, our return on equity in 2012 using core results was 14.6%, and the return on capital employed was 12.6%. Copies of the press release announcing our fourth quarter earnings and the investor relations supplemental schedules are available on our website at www.oxy.com or through the SEC's EDGAR system.
I will now turn the call over to Steve Chazen to comment on 2012 performance, as well as year-end oil and gas reserves, and discuss our 2013 capital program and provide guidance for the first half of the year.
Thank you, Cynthia. Oxy's oil and gas segment produced record volumes for the ninth consecutive quarter and continued to execute on our oil production growth strategy. Fourth quarter domestic production of 475,000 barrel equivalents a day, consisting of 342,000 barrels of liquids and 800 million cubic feet of gas per day, was an increase of 6,000 barrel equivalents per day compared to the third quarter of 2012. The increase in our domestic production over the third quarter in 2012, almost entirely in oil, which grew from 260,000 barrels a day to 265,000. Gas production declined 12 million cubic feet a day on a sequential quarterly basis, mainly in the Mid-Continent, which reflects the reduction in gas-directed drilling we have mentioned over the past couple of quarters. Higher natural gas liquids volumes resulting from better yields from our new Elk Hills gas plant offset the decline in gas production there.
Our total domestic production grew from 428,000 barrels a day in 2011 to 465,000 barrels a day in 2012, or about 9%. Our total domestic oil production grew by 11%, from 230,000 barrels a day in 2011 to 255,000 barrels a day last year. The company's total daily production reached a record of 779,000 barrels a day in the fourth quarter and 766,000 barrels for the full year. This resulted in a 5% increase for the year. We have embarked on an aggressive plan to improve our operational efficiencies over all cost categories, including capital, with a view towards achieving an appreciable reduction in our operating expenses and drilling costs to at least 2011 levels in order to create higher margins from our production. With regard to driving efficiencies in our cash operating costs, we are running well ahead of my earlier plan.
We recognize that cost efficiency is the result of many decisions that are made at all levels of the organization, in particular, numerous decisions that are made at the field level. All of our business units stepped up to the challenge of reducing our costs and involved their personnel at all levels, from business unit management all the way to field-level personnel to generate ideas to improve cost efficiency. Our employees have responded well to the challenge. The business units generated many good ideas, large numbers of which were generated by field-level personnel. Many of these ideas have already been implemented, and the results are apparent through reductions already realized in operating costs. There are still many more big and small ideas that are in the process of being implemented, which we believe will result in additional improvements.
In the fourth quarter, the company's total production costs were $1.04 a barrel lower than the third quarter. Improvements were realized across most business units, most notably the Permian and Elk Hills. Reductions resulted from efficiencies achieved across most cost categories, including savings in surface operations, reductions in the use of outside contractors, curtailment of uneconomic downhole maintenance, and workover activity, as well as related overhead. In 2013, we expect to realize further improvements in all of these categories. We expect our production cost per barrel to be under $14 in 2013, which is significantly lower than 2012 average costs. Many of the steps already taken in the fourth quarter, which is only partially reflected in the quarter's average costs, along with additional measures being implemented early in the year to result in meaningful additional cost reductions in 2013 and beyond.
We are also seeing strong early results from our efforts towards improving drilling efficiency and cutting our well costs through simplification of our well design, focusing on activities in fewer geologic plays, and favoring higher return conventional activity. Our goal for 2013 is to reduce our U.S. drilling costs by 15% compared to 2012. We're approximately halfway towards that target, with further improvements expected during the next couple of quarters. We've increased our dividends at a compounded rate of 15.8% over the last 10 years through 11 dividend increases. We expect to announce a further dividend increase after the meeting of the board of directors in the second week of February. As a result of our consistent long-term record of growing our dividend, we are proud to have been selected for inclusion in Mergent's Dividend Achievers indices for 2013.
This is a highly regarded series of indices that track companies with strong long-term dividend growth. We haven't completed our determination of our year-end reserve levels, but based on our preliminary estimates, we produced approximately 280 million barrels of oil equivalent in 2012. Our total company reserve replacement category from all categories, including revisions, was about 143%, or about 400 million barrels. Depressed domestic gas prices and changes in our plans for drilling on gas properties resulted in negative revisions to our domestic gas reserves. Natural gas reserve revisions represented approximately 60% of the total revisions. If gas prices recover in the future, a portion of these reserves will be reinstated. Additionally, we experienced some negative revisions due to reservoir performance. Our 2012 development program, excluding acquisitions and revisions, replaced about 175% of our production with about 490 million barrels of reserve adds.
Our 2012 program, including acquisitions but excluding revisions of prior estimates, replaced 209% of our production. We believe these latter two approaches are appropriate way to evaluating the progress of our overall program. At year-end, we estimate that 72% of our total proved reserves were liquids. Of the total reserves, about 73% were proved developed reserves. I'll now turn to our 2013 outlook. Domestically, we expect oil production for all of 2013 to grow by about 8%-10% from the 2012 average. With lower drilling on gas properties, we expect gas and NGL production to decline somewhat. Plant turnarounds in the Permian CO2 business will cause additional volatility production in the first half of the year. Internationally, at current prices, we expect production to be lower in the first quarter due to a planned turnaround in Qatar.
Production should be relatively flat for the rest of the year compared to the fourth quarter, although there is some possibility for growth. In our capital program, we are currently in an investing phase in many of our businesses, where a higher than normal portion of our capital is spent on good longer-term projects. In 2013, we expect to spend about 25% of our total capital expenditure on projects that will make a significant contribution to our earnings and cash flow over the next several years. I previously talked about the excellent Al Hosn Gas project. We have also started the construction of the BridgeTex Pipeline, which we'd expect will start operations in 2014. This pipeline designed to deliver crude oil from West Texas to the Houston area refineries, which will open up additional markets for oil from the Permian region and improve our margins.
We're also investing in gas and CO2 processing plants to expand the capacity of these facilities to handle future production plants and in a new chlor-alkali plant in the chemical business. Our total capital spending is expected to decline by approximately 6% in 2013 to $9.6 billion from the $10.2 billion we spent in 2012. The reduction in capital will come entirely from the oil and gas business, where fourth quarter spending rate was already close to the level planned for all of 2013. Almost all the reductions will be made in domestic operations. Midstream capital spending will increase mainly for the BridgeTex Pipeline. 2013 program breakdown is expected to be 75% in oil and gas, 11% in the Al Hosn Gas project, 9% in domestic midstream, and the rest in chemicals. Following is a geographic review of the 2013 program.
In domestic oil and gas, development capital will be about 46% of our total capital program. We expect our average rig count in the U.S. to be about 55 rigs during 2013 compared to 64 rigs in 2012, a decline of about 14%. We've eliminated our less productive rigs to improve our returns. Our total domestic oil and gas capital is expected to decrease about $900 million compared to 2012. Permian capital should remain flat. In California, we expect to reduce capital about $500 million from 2012 levels, which represents ongoing well cost reductions and efficiencies and a modest shift towards more conventional drilling opportunities and the constraints of the current environment. To improve the efficiency of our capital spending in California, we have planned our 2013 program level based on what we know we can execute with our existing and conservatively anticipated permits.
We may revise our program during the course of the year if we can gain more certainty about the environment. In the Mid-Continent, we expect to reduce spending by about $400 million from 2012 levels. We have reduced activities in higher cost, unconventional levels, specifically in the Williston and in the lower return gas properties, mainly in the Mid-Continent and Rockies. The modest decline in rig levels compared with well cost reductions will lead to an overall decline in the U.S. spending compared to 2012. However, as a result of planned efficiencies, we can drill a similar number of wells as we drilled in 2012. Compared to 2012's split, we will spend a higher percentage of our 2013 capital on oil projects. As a result, U.S. oil production is expected to continue to grow this year.
Internationally, our total Al Hosn Gas project will decline modestly from 2012 levels and will make up about 11% of our total capital for the year. While Iraq spending levels continue to be difficult to predict reliably, capital in the rest of the Middle East region is expected to be comparable to 2012 levels. Exploration capital should decrease about 15% from 2012 levels and represent about 5% of the total capital program. The focus of the program domestically will be in the Permian Basin in California, with additional international drilling in Oman. The midstream capital will increase by about $400 million due to the BridgeTex Pipeline project. Chemical segment will spend about $425 million, which includes construction of a new 182,500 ton per year membrane chlor-alkali plant in New Johnsonville, Tennessee, that we expect to begin operations in the fourth quarter.
In summary, assuming similar oil and gas prices into 2012 and our expectation of comparable chemical and midstream segment earnings, we expect our 2013 program will generate cash flow from operations of about $12.7 billion and invest about $9.6 billion in capital spending. In 2012, we returned $2.3 billion in total cash to shareholders in the form of dividends and share repurchases, excluding the fourth quarter accelerated payout. Our dividends, excluding the fourth quarter accelerated payout in 2012, was $1.7 billion. We expect this amount to increase in 2013 on an annualized basis by an amount comparable to our recent dividend growth rate. We expect that a $5 change in our realized oil prices will change cash flow from operations by about $450 million. We're now ready to take your questions.
Thank you. At this time, if you would like to ask a question, press star, then the number 1 on your telephone keypad. Your first question comes from Doug Pearson of ISI.
Good morning, everybody.
Morning, Doug. How are you?
I'm doing fine. Steve, it sounds like the teams have been very successful in identifying some of these expense opportunities and at a pretty surprising pace. My question is whether or not the early success indicates that there may be a greater potential than you guys had originally envisioned. You talked about several cost categories in your commentary. The second question is, were you surprised by the opportunities in particular areas, or were the savings fairly broad-based and spread out?
Bill will answer in more detail, but on the overview, I think both Bill and I have been stunned by how the people, especially in the field operations, have responded to this. A lot of great ideas. Some of them may be a little off in left field, but a lot of great ideas. We've been very pleased with this.
Good.
It's really spread over a lot of categories. There's no one thing we can point out and say it was caused by this or that. I think we have maybe let Bill talk about it here for a minute.
Okay.
Bill's been out talking to the people in the field.
Okay.
Doug, can you hear me? Hello?
Yes, I can hear you.
Okay, very good. Like Steve said, these savings have been generated both on the capital side as well as the operating cost side. I see more than 50% toward our goal on the operating expense side, more like two-thirds of the way there.
Wow.
It's across a lot of different categories. Just top to bottom, not just one specific thing.
Okay, great.
I'd like to go back, Doug.
Yeah.
The goal here is not just cutting the costs, but making more margin.
Sure.
It isn't just about, we cut the cost by closing down a facility or something. The goal is creating more margin. So far, we haven't seen any reduction in our production as a result of this.
Great. Thanks a lot.
Thank you. Our next question comes from Evan Calio of Morgan Stanley.
Hi, this is actually Drew Vanker. Just wanted to ask you guys, there's been a number of shareholder initiatives in the past few months, targeted mainly at upstream companies, revolving around separating business lines to boost valuation. One could argue that your chemicals and midstream business could receive a similar valuation uplift. What are your thoughts around separating those segments from the upstream?
We're open to any ideas that will generate real value. The midstream segment is, I'd hate to use the bad word, but integrated with our mostly Permian operations. We believe that our oil company gets better prices for the product, the oil. Putting it in a form where some third party shared in that may not be the best thing to do. This is a chlorine caustic business. Chemical companies, as a group, don't generate huge multiples. Maybe there's other things people could talk about doing. We look at all this stuff regularly to see whether there's real value could be created. Both Ray and I are large shareholders in the business. We're not here to collect salaries. From our perspective, most of our net worth, or at least I'll say it for me-
Me too
Is tied up in this. From our perspective, we're perfectly aligned with the shareholders in this. Our goal is to make the stock go up and increase our net worth that way, rather than through a 5% increase in our salary or something. I think we're perfectly aligned. A lot of people I know in the business don't have a lot of stock. We're perfectly aligned on this, and we continue to look at things that make sense that will increase value. Those two segments are small compared to the total. I'd be very cautious about the midstream because it's so heavily integrated into our margins in the Permian.
One of the advantages we have in the Permian is we control our own infrastructure. To be a fiduciary, while you still could control it, being a fiduciary is not necessarily what you want to be. We can get Willie. Willie Chiang, who runs that business, can maybe talk about it a little bit.
I'm going to make a comment on just what we're seeing in the fourth quarter and first quarter. The differentials, you can see how they've been significantly depressed fourth quarter because of turnarounds and pipeline maintenance out of the Permian. We were seeing significant discounts. I think a good example of what Steve talked about is our project that we're working with Magellan on BridgeTex to get access to the Gulf Coast through Colorado City, which is essentially Midland. As you all well know, when you have constrained supply, that's not a good thing. Price signals work, infrastructure gets built, and we're able to match supply with demand and get access to other markets. I think to do that without control in a midstream company is a little more difficult. We see it as a real advantage that we have.
Okay.
That's all for us. Thanks.
Thank you. Your next question comes from Doug Leggate of Bank of America Merrill Lynch.
Thanks. Good morning, everybody.
Morning, Doug.
A couple, please, Steve. Steve, on the cost cutting, you signaled earlier this year at a competitor conference how this had been going. A couple of months ago, when I had the opportunity to travel with you also signaled that you've had a 50% increase in cash OpEx between first quarter 2011 and the third quarter of 2012. That suggests there could be a lot further to go. Could you give us an idea of just how you're feeling about getting back to that early 2011 cash OpEx number as a stretch goal, and then what you might do with the incremental cash flow that clearly would be quite significant coming out of that? I have a follow-up, please.
Yeah. I hate to overpromise here. I think we'll stick with our current outlook. Both Bill and I have been surprised, and Sandy's operations too, been surprised at a lot of the ideas that have been generated. While I'm, I don't know if the word is euphoric, for me, euphoric about what we're doing, I just don't want to get ahead of ourselves. We'll deliver what we say and hopefully a bit more. I really don't want to go into overstating it, but it's certainly looking very strong right now. What are we going to do with the cash? We've talked about this forever. When the stock was poor after the last call, we stepped up and bought a fair number of shares. If I'd have known it was going to respond so quickly, the stock, I would've bought more shares, admittedly.
My ability to predict the stock price is modest on a good day. There could be some of that. There could be higher dividend growth. The goals are still the same. When the stock price doesn't reflect the reality of the business, that'll be used. When people get negative about the stock for usually short-term reasons, we'll deal with that. Dividends are an important part of the business. Exactly what we're going to do, I don't know. Even with the numbers I've given you should understand, with the numbers, the cash from operations less the capital, there's $3.1 billion of difference, and that's really last year's product prices. That I think I've been reasonable, if you will, in figuring that number out.
I think that with the dividends taking a little more than half of that, it still leaves a fair amount left. I would expect over time, that number will widen. The Al Hosn project, which if somebody asks about it, we'll get Sandy to talk about. Al Hosn project is going to add a lot of cash flow to the company and obviously reduce our capital spend. As we look forward to 2015, late 2014 maybe, but 2015 for sure, company's cash flow will grow. We can't treat our business the same as a small producer. Small producer takes all his money and drills wells with it. His current production may look a little better.
We have to spend a fair amount of our money on the long term, and the projects like Al Hosn and maybe additional projects in the Middle East will help our business over time. You suffer a little bit now, but in the long run, these are things that build the company out. If that answers your question.
That's a very helpful answer. Thank you, Steve. My follow-up hopefully will be a little quicker. The transition to a little bit more conventional drilling in California, I guess this is a kind of bread-and-butter exploration you guys talked about a couple of years ago. Could you just elaborate a little bit as to what you're seeing in terms of the split of activity and what expectations you have out of that program? I'll leave it there. Thanks.
It's a slight shift, actually. It's not a huge shift. One of the issues we had, I had really last year, was that as we tried to boost the program, we counted on being able to drill, and if we didn't get the permit or whatever, you wound with a fair amount of rig inefficiency because you couldn't drill the well. You had to find some other location for the rig. We've put in a very conservative program this year that can be delivered fairly straightforwardly without a lot of problem, with decent results, we think, and better results than we had last year. As the issues clarify later in the year, and if we see good opportunities, we could shift. I think right now we want high certainty, good returns, and that's what we're doing in California and in the Permian.
That's really the goal of this year. If we see better opportunities later on, we'll do that.
Great. Thanks, Steve.
Thank you.
Your next question comes from Ed Westlake of Credit Suisse.
Hey, good morning, everyone.
Morning.
The first question is just on depreciation. Obviously, you've given a guidance of $17. Now you're obviously spending more and you've got the Al Hosn unproductive CapEx. As you look out a bit further beyond this year, do you think depreciation will just continue to rise with the capital spend? Or are there some moving levers to expect DD&A to flatten out at some point?
I think it's likely to flatten out. We're very close. If you look at the program, forget the revisions. If you just look at the program and the overall finding and development cost of the program, once you see those numbers, you haven't seen them yet, of course. You'll see that the $17 is very close to what we're doing worldwide. When Al Hosn comes on, the depreciation expense per BOE is going to fall for the company, because you're going to get low depreciation barrels. I can't say it won't vary a little bit, but I think as we roll through this year, we ought to be okay. I think our F&D on the program basis, again, ignoring revisions, is actually pretty good. I think that this is, you don't really know, of course, but we're very close here.
I think we have to sort of suffer through it this year, and as we roll into next year and the year after, we ought to see improvements in the DD&A just from what we have in our portfolio. In addition, we should pick up some margin on our oil barrels in the Permian as that market equilibrates. I think that then some additional chemical earnings from the new plant. I think our overall cash from operations and earnings will get better, but I think we're close here on the DD&A. There's not really much more. In the charge, we took out some of the things that were a drag on it.
Okay. Then shifting to the Permian. Permian capital's flat, California capital's down. I think from the presentation you released earlier this year, the net share of Permian acreage is increasing. Could you just give us an update on the rig program that you plan actually in the Permian and maybe some of the EURs and rig costs that you're seeing in the horizontal program in particular? I guess a follow-on would be how much production you think you'll get from the acquisitions that you made in 2012 and 2013. Thank you.
I'll answer the last part and let Bill talk about the Permian program. Last part is we picked up a few thousand barrels a day in the Permian in the fourth quarter, under five, surely. 3,000 or 4,000 a day, I would guess, time we're through. We picked up a little gas in California. I did sell forward, or whatever the term of art is for that, the gas that we bought at a little over $4 an Mcf for 15 months. We get about a third of our money back in the 15 months that we put into it. On that basis, a reasonable cost. That's really all you'll probably see. Bill can talk about our Permian program and a lot smarter than I am.
Ed, we're looking to average somewhere between 25 to 27 rigs in the Permian. Roughly a third of that program will be in the Wolfberry, which we've spoken to you about in previous calls. Another third is going to be mainly in the Delaware Basin. The remainder will be centered around several other anchor-type programs. Of course, the well cost that you mentioned, horizontals, depends on a lot of things, lateral length, the depth of the well and those sorts of things. What we've seen is about a 50% or so overall weighted average capital cost reduction in a number of our anchor programs in the Permian.
Okay. That was a 50 or 15? Sorry.
I meant to say 15.
15.
Yeah. It's 15.
I thought 50 would be quite.
He has a new target now.
Okay, great. Well, thanks very much.
No, it's 15.
Helpful.
There's some guy in the Permian that just had a heart attack.
Thanks, Ed.
Thanks, Ed.
Your next question comes from Leo Mariani of RBC.
Hey, guys. Just hoping for a little bit more detail on the Permian. Are you guys planning on significantly increasing horizontal Permian activity in 2013 versus 2012?
Bill can answer that.
Yeah. Leo, really, not so much. Only about 15%-20% or so of our wells in the Permian are going to be true horizontals. Now having said that, we do drill a number of highly deviated wells, but those are still not horizontals. It's only in certain specific limited plays, where we're drilling horizontal wells.
Okay. Just in terms of the Bakken, it sounds like that's an area you guys made probably the most significant cuts, if I'm not wrong, in that statement. Just any thoughts around when that activity could pick back up if you guys get to your cost reduction targets, where you expect that to pick back up later in 2013? Just any color you had around that would be helpful.
Well, we've already seen some sizable, actually, reductions in the cost, but we're not where we need to be. We're going to continue to drill at a moderate rate there, and see what goes on. We're down to sort of all right numbers. Of course, the product price is now better there than it's been. I think we'll hold this level, likely hold this level this year of drilling, and work on reducing our costs and spending less time moving rigs because there's a lot of money we've spent on moving rigs around. If you concentrate your program in a few places, we can, I think, get better results. Once we see better results, I think we can boost the program next year. We're trying to keep the capital under control this year. There's always more money that could be spent.
We could spend some more money here, we could spend some more money there. We're trying to keep the program under control this year. Next year, as the capital needs of some of the longer term projects start to roll over, we can look at what's the best use of the capital. For this year, I think we're trying to be conservative and only spend the money on the best things we can.
All right. That's helpful. I think Steve, you mentioned potentially other projects in the Middle East. Is there anything kind of looming in 2013 on the near term horizon?
Sandy?
We're working on projects, small incremental additions in Oman and bringing on our Block 62 properties. We're also in the queue, hopefully for more Abu Dhabi related projects. Nothing exactly on the horizon in 2013.
The Middle East should be viewed, I view it like the Permian some ways. You go through long periods in the Permian where it's quiet, and then all of a sudden something new comes along and you get a period of growth, and then you go through another period. For the Middle East, we're in the building phase. As the time progresses, it'll again be the star for a period and something, and then it'll come down again. The whole business is cyclical. This isn't a business that's-- and fairly long term. In the Middle East, I think you really have to take a long view of it and focus on those things that you can manage and things that will generate long term returns. Once one of these projects is running, they generate a lot of cash and earnings for the company.
You just have to invest to get there.
Thanks a lot, guys.
Our next question comes from Paul Sankey of Deutsche Bank.
Hi, everyone. On the volumes, Steve, in the past, you've talked about 5%-8% at a global level. This may be an unnecessary detail, but it's not a number that you've put out. You haven't put out a total volume target. I'm not sure it particularly matters, but I guess implied you would be at a kind of a 5% company level growth for next year. Is there any particular reason that you're not specifying that 5%-8%?
Yeah, there is. The target still exists. That's not argued. The target's there because we grew about 5% last year. If we look ahead to the Al Hosn project going on, for the multi-year period, you'll be there. The reason I'm not is, as we cut back on the gas drilling, the outlooks that we have are difficult to measure exactly, because they tend generally to overstate the decline because of the way they compute it. It's really about the U.S. gas, and that's the only thing that I view as-- that's why we're not I wish you guys would stop talking about BOEs or at least convert it 25 to one or something. That's really our issue, is that our gas production, you just don't know what's going to happen exactly.
We can predict the oil production, I think, reasonably well because the program is focused on that, and it's pretty reliable, and it's designed to be conservatively estimated. The gas is just hard. That's why we're staying away from the BOE sort of calculation. As far as profitability goes, this is where the money is. If somebody thinks we ought to drill some gas wells to break even, I suppose we can do that to make some BOE numbers. The money right now is in oil. I mean, black oil, I don't mean NGLs. That's why we're doing it.
Yeah, totally understood. In the past, you've also been frank about how difficult it is to forecast the gas number. You said the same thing about the international volumes. How confident, I mean.
No, just Iraq. Right. The reason in Iraq is we don't know what the capital is because it's not in our control. There's another operator there, so if they spend more money, you'll get more production. If they spend less, you'll get less production. On a cash flow basis, you get the money back so quick. Let's say you put another $200 million, or whatever the number is, into capital, you'll get the $200 million back within six months. That's the number that it's not in our control. Things that are in control, we can at least more or less figure, but things that are not in our control and in the control of somebody else, it's just very hard. You can wind up a lot more or fewer barrels in Iraq, depending on what they spend. Nobody should be bothered by that, really.
It's like gas decline, not something I can estimate. It's even more out of control because it's a third-party operator operating in a difficult environment.
Yeah, I totally understand. On acquisitions, you talked about transitioning to more of an organic approach. A couple of years ago, we hit highs of $5 billion of acquisitions per year. You said this past year was $2.5 billion. Can you talk a bit about where acquisitions will fit in 2013? Again, best guess.
It just depends. We can't create acquisitions. Somebody has to want to sell. At the end of last year, for tax reasons or whatever, we had to rush people in the fourth quarter. If you want a lot of acquisitions, you ought to go speak to people in Washington about talking about raising capital gains taxes or something, and we'll get more acquisitions. We can't really predict it. $1 billion-$1.5 billion is probably sort of there at some point, but we don't see anything this quarter that amounts to anything. There's really no activity, and nothing really that amounts to anything on the horizon. Right now, in the areas we would acquire, which is basically the Permian, we've got a full program.
It's one we can manage, and the acquisitions right now, especially capital-intensive ones, which is almost all of these are now, are not a high priority.
Yeah, disposals. What about the Bakken?
Well, anything that adds value, we would look at. If the costs were a little better, and it's a place where there's a lot of oil in the U.S., the differentials have gone away. If somebody would like to buy my desk, if they pay the right price, they're more than welcome to it. There's not much in the drawers.
Great. Thank you. Just finally from me, if I could, while you've got Willie Chiang there as well, you referenced the Midland differentials, you've also spoken about good realizations essentially for the company. There's the midstream element. Just sort of squaring the circle, I think what you're saying is that you get already a relatively premium price in the Permian because of the infrastructure access that you have, and that we shouldn't look too hard at these Midland differentials as being that meaningful for you. At the same time, you're adding more pipeline capacity to further avoid any risk. How should we kind of put all of that together? Thanks.
Yeah. We'll let Willie answer that.
Yeah. Hi, Paul.
Hey.
I think, if you look at the infrastructure in the industry right now, the infrastructure has lagged the price signals. Price signals haven't been there. People haven't built out. We all wish we would've built more infrastructure earlier. We don't deal only with the Brent-WTI spread. We also have the Midland to Cushing spread. If you're limited in pipeline capacity takeaway, as we are currently in the Permian, we saw some huge differentials fourth quarter with combined turnarounds, as I talked about, and some pipeline maintenance.
Sorry, I was just going to interrupt and just say that, so the point is that you did suffer from those differentials?
Oh, yeah.
We didn't suffer much, that's true.
Okay. Keep going, Willie. Sorry.
Well, my point is, yeah, by putting more infrastructure in and making sure we have access to different markets, I think going forward, you should see that we won't get as impacted with any of these abnormalities between the basis differentials between regions.
Right. Finally, Willie, I guess you expect LLS prices to be pressured down and Permian prices to rise in some combination. What's your thoughts? I'll leave it there. Thank you.
I think there's a lot of other people kind of looking at LLS prices and different basis differentials. Our key is getting Permian to the Gulf and making sure we get the highest prices possible.
We're not good at oil price forecasting.
Thanks, guys.
Thank you.
Your next question comes from Matt Portillo of Tudor, Pickering, Holt.
Good morning, guys.
Morning.
Just two quick questions from me. As we think about your free cash flow growth in the outer years and kind of the near-term focus on reduction in capital spend Steve, I think you alluded to the fact that the incremental capital or the incremental free cash flow may go to dividend increase. Just trying to understand how you guys are thinking about that relative to the historical growth rate, should we expect to potentially see that accelerate over the next few years as you roll off some of these major projects?
First of all, it's a board decision, not mine. I'll have a view, but it's not my decision to make. Everybody here is committed to dividend growth. Exactly what it'll be, just depends. It just depends on how predictable it is. Also depends on the stock price to some extent. If we get downward movement in the stock price, we may shift some more money to buying in some shares. You should expect double-digit growth in the dividends, going forward. Whether we know exactly what it'll be in any one year is hard to say. I think as we look through this whole process over the next two or three years, we ought to see increased free cash flow and ability to pay higher dividends.
Great. Just a second question for me on, just looking through the slides quickly here. Approximately 60% of the reserve revision was related to gas price. The other 40%, I guess, was related to reservoir performance. Could you give a little color around where we should have just expected regionally to see that revision on the reservoir side, and any color as to what drove that revision downwards?
Yeah, I think the Mid-Continent had some performance issues in some of the gas reservoirs. There's an old reservoir in Old Elk Hills which underperformed. I think those are the two major areas where there was performance revisions.
Thank you very much.
Pure performance revisions.
Thank you.
Your next question comes from Faisel Khan of Citi.
Thanks. Good afternoon.
Hi.
Hi. Just a few questions. You'd mentioned before that you had a high number of contractors earlier in the year, and that part of the cost reduction effort was removing some of those contractors from the cost structure. Can you give us an idea of what the number of contractors were at the beginning of this cost reduction effort, and where they are today?
Contractors are a difficult number because there's guys out in the field that are contractors. You hire Halliburton or something. That's really not what we're talking about. These are mostly office-related contractors. The number is, I think Hmm?
It's in the hundreds.
Yeah, hundreds of them. How many have you let go?
That's how many we've let go, Steve.
Yeah.
It's in the high hundreds.
High hundreds. That's maybe 20%, 25% of what's there.
Okay.
These aren't the contractors like the Halliburtons out. This isn't guys doing work over. These are guys primarily in the offices.
Is there more of this kind of cutting to go, or you think you're done at this point with this part of the process?
You're never done looking at costs. Nobody's ever done. When you take a layer out, you look at where you are, you see what's going on. You see if you're hurting your production, hurting your margins. Then you go look at it again. You take the things that you know you can handle first, then you move down the road. Getting done with looking at the costs, it just never happens. There's no plan that sits every month we're going to fire 100 contractors or something.
Okay. Fair enough.
We're trying to do it in a way that's not done with a meat ax, but with a scalpel.
Okay. Understood. On the reserve additions, I think previously you had not booked anything for the Shah Gas project. At this point, I'm not sure if you have or haven't, but was that part of the reserve additions, the $400 million?
Yes, it was.
Okay. Was that a big part of it, or?
Yes, it was.
Okay. Understood.
We've spent $2.6 billion, I think, so far. Isn't that right, Sandy? We spent $2.6 billion on it so far, so I would assume that there'd be some reserve additions associated with this spending. We've only booked maybe a third to 40% at best of the reserves, and we've spent What, Sandy?
We spent about 70% of the money.
Yeah. We're pretty far behind the booking relative to the spending. You should expect to see more additions over the next two or three years. Really beyond that, as the project matures and there's more opportunity for gas delivery, I think you'll see a lot more additions. I think we're very early in the booking here, and this is about as little as we could actually book given the facts.
Okay, understood. Then on the $2.5 billion of acquisitions you made this year, what production did that add to your portfolio during the year, and what geographies, or how much acreage did you guys pick up in those $2.5 billion of acquisitions?
I don't really know. Most of it was done in the fourth quarter, so it didn't add anything. You picked up a little bit in the early part of the year, but virtually nothing really. A few thousand barrels a day, maybe, in the last year, but almost all of the production basically closed the end of the year. Last year was sort of nothing.
Okay. Was this mostly centered in the Permian or also in California and other parts?
The production, it's always the same. Permian is the largest piece. Hopefully, every so often you find a piece in California, but it gets harder and harder for us. Some occasionally in the Bakken, if you can get the right price. It doesn't really change the strategy, the plan, the acquisitions don't change very much. Occasionally, you'll find something in South Texas maybe that adds to what we have, but those tend to be pretty small.
Okay. On your production growth guidance for domestic oil volume, the 10%-11% sort of number that you have out there, I take it that's also mostly, most of that growth is coming from the Permian or what do you expect-
No
California to contribute to that growth?
No. The oil production will come from Permian and California, both, and maybe a little out of the Bakken even.
Okay.
We're spending the money in the Permian, that's where you ought to see it. We're all spending a fair amount of money in California, and again, they're focused on oil drilling. California oil production, as we get through and as we head into 2014, will grow sharply as some of these steam floods and other things start to come on. Once we get through the permitting phase of that activity, you'll see some more volume, oil volume growth into 2014 and 2015.
Okay. Thanks for the time. Appreciate it.
Thank you.
Your next question comes from Roger Read of Wells Fargo.
Good morning. Kind of walk us through that, if you would.
Well, it's all of the above. I think we've said this before, but if you over-drill high decline wells, while it may excite you for this quarter or next quarter or something, it makes next year more difficult because you're faced with high decline wells. Our program is a balance of all those activities. It's designed to make a sustainable program, not one that gets a big level write-off.
Well, I understand that. If you're looking at it, and I know you look at your overall portfolio from very much the return criteria, if the returns were the same for the horizontal wells or potentially even better, would you move more aggressively towards that? Is it the decline rates and the year-over-year comps have become tougher that keeps you from looking more aggressively?
We'll let Bill answer. He knows more about it than I do.
Hey, Roger, really what dictates an increase in horizontal drilling is the reservoir and the target that you're going after. Which is why in the Permian, as I said earlier, you really don't see a huge proportion of your wells being horizontal because we've got other targets, multiple pay type targets and reservoirs that are more amenable to vertical drilling as opposed to horizontal. Really what dictates it more than anything is the target.
Okay. That kind of falls into my next question. If we look at a lot of the other operators out there, they're talking about moving to, say 50% horizontal, 75% horizontal. If we separated out the CO2-related drilling out there and really just sort of looked at the highly deviated wells and the horizontal wells, how would you compare to that? I'm just trying to understand where you fit in, where you will be fitting in over the next, say, 12 to 24 months.
Well, I think as some of these unconventional plays prove themselves up, I think you could expect to see a little bit more increase in horizontal drilling. As I said before, a third of our program is in the Wolfberry, which is vertical drilling essentially, and another third is in the Delaware Basin, which again, is largely driven by vertical drilling. As some of these unconventional plays mature, I think you'll see a little bit more in the way of horizontal holes in those reservoirs.
We have a lot of acreage. We're not trying to spend the maximum amount of money right off the bat. We're trying to learn from what other people are doing and cut through it. While other people have maybe less acreage or less opportunity, they're basically into this, and we'll learn from them, and we'll be in some of their wells because of our large position. Rather than go and be the experimenter, we can actually learn for a relatively low cost to figure out whether these things make sense. These plays are relatively new. Determining the ultimate recoverable reserves of a play that's a year old or 18 months old when you have huge decline, initial decline rates, is very difficult. We tend to be fairly conservative about how we look at it because we don't know how the curve is going to flatten.
That's maybe just us, but we can afford to wait, be patient and thoughtful about this. We're maybe less convinced than other people about the ultimate recovery. We'll find out here in the next year or two as these plays mature, and our position is good enough that we can do that.
Okay. That's helpful. Thank you.
Thank you.
Your next question comes from Eliot Javanmardi of Capital One.
Thank you. Congrats on the quarter. I think many of the questions have been asked already. I did want to ask you one more. You had mentioned that it looks like you're now two-thirds of the way through your cost-cutting goals. Want to get some clarification around what number we're looking at to start with and what number we're trying to end with in that, just from a clarification standpoint. Could you help me out there?
Bill will answer that.
On an absolute dollar basis, Eliot, we're looking at $450-$500 million of reduction in absolute OpEx. That's on the domestic side.
Okay. What was the timeframe to meet that target? It was mid-year for 2013, or?
That's an overall average target for 2013.
Okay, you're two-thirds of the way.
As you think about it, you should think about it's a little less in the beginning. The exit rate will be different. It will be higher. Otherwise, you won't make the average.
I see. I understand. Okay, great. That's all I had for you. Thank you, guys.
Thank you. Your last question comes from John Herrlin of Societe Generale.
Yeah, thanks. Good to hear you're more chipper, Steve.
Well, it just depends on the time of the day.
Oh, there you go. Couple quick ones. With the cost savings.
I had more coffee this morning.
Well, that's good then. With the cost savings, it's all the Oxy initiatives, no help on the services side at all?
Very little. We're not ignoring that.
Okay.
Right now it's really all within our power.
Okay.
We're not planning that, but there's clearly some out there.
Okay.
We would hope to get some from that. What we're planning on is what we could do within our control.
Okay. With the Elk Hills plant, is that now fully operational?
Yes.
Are you running it full? Okay.
Yeah, you can see how it's generating more NGLs. You can't see it exactly, the gas is down at Elk Hills, the equivalent amount of BOEs were converted into NGLs. Even though we're getting not good gas prices, but relatively good gas prices in California, you get better prices for NGLs.
Correct. Thank you.
Thanks.