Occidental Petroleum Corporation (OXY) Q4 2012 Earnings Report, Transcript and Summary

Christopher G. Stavros - Vice President of Investor Relations and Treasurer Cynthia L. Walker - Chief Financial Officer and Executive Vice President Stephen I. Chazen - Chief Executive Officer, President and Director William E. Albrecht - President W. C. W. Chiang - Executive Vice President of Operations Edward Arthur Lowe - Vice President and President of Oxy Oil and Gas -International Production

Douglas Terreson - ISI Group Inc., Research Division Andrew Venker - Morgan Stanley, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Edward Westlake - Crédit Suisse AG, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Paul Sankey - Deutsche Bank AG, Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Faisel Khan - Citigroup Inc, Research Division Roger D. Read - Wells Fargo Securities, LLC, Research Division Eliot Javanmardi - Capital One Southcoast, Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research

Good afternoon. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum Fourth Quarter 2012 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Christopher Stavros. Please go ahead sir.

Thank you, Christie. Good morning, and 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 and 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; and our Executive Chairman 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 and 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, and 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 and $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. It's partially offset by lower earnings in the midstream segment. In the fourth quarter, we recorded pretax 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 4 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. Also, 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, and 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 for the -- 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 in 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%. And 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 pretax 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, were generally related -- 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 cost. 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 5 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 31. 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. And 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 in 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 -- domestic 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 a 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 cost were $1.04 per barrel lower than the third quarter. Improvements were realized across most business units, most notably the Permian and Elk Hills. The 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 work-over 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 high return -- higher return conventional activity. Our goal for 2013 is to reduce our U.S. drilling costs by 15% compared to 2012 and we are 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 further dividend increase after the meeting of the Board of Directors in the second quarter 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 long -- 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 revision 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 reservations 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 2 approaches are an 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% to 10% from the 2012 average. With lower drilling on gas properties, we expect gas and NGL production to decline somewhat. Planned 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 contributions to our earnings and cash flow over the next several years. I previously talked about the excellent Al Hosn gas project. We've also started the construction of the BridgeTex pipeline, which we'd expect to start operations in 2014. This pipeline is 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 the fourth quarter spending rate was already close to the level planned for all of 2013. Almost all of reductions will be made in domestic operations. Midstream capital spending will increase mainly for the BridgeTex pipeline. The 2013 program breakdown is expected to be 75% oil and gas, 11% in the Al Hosn gas project, 9% in domestic midstream and the rest in chemicals. The 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 United States 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 the 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 reduced activities in higher-cost unconventional levels, specifically in the Williston and the lower-return gas properties, mainly in the Mid-Continent and Rockies. The modest decline in rig levels compared with well cost reductions lead to an overall U.S. oil and gas -- a decline in the U.S -- overall U.S. spending compared to 2012. However, as a result of planned efficiencies, we can drill a similar number of wells as we did in 2012. Compared to 2012 split, we will spend a higher percentage of our 2013 capital on oil projects. As a result, U.S. oil production is expected to grow -- 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's 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 and 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, 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 amount comparable to our recent dividend growth rate. We expected 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.

[Operator Instructions] And your first question comes from Doug Terreson of ISI.

Steve, it sounds like the teams have been very successful in identifying some of these expense opportunities and at a pretty surprising pace. So my question is whether or not their early success indicates that there may be greater potential than you guys had originally envisioned? And you talked about several cross-categories in your commentary, and 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 answered in more detail. But on the overview, we've been -- I think both Bill and I have been stunned by how the people, especially in the field operations, have responded to this. So a lot of great ideas, some of them maybe a little off in left field, but a lot of great ideas. And so we've been very pleased with this. I think Bill can give -- and 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. And I think maybe I'll let Bill talk about it here for a minute because Bill's been out talking to the people in the field.

Doug, can you hear me? Hello? Okay. Very good. Like Steve said, these savings have been generated both on the capital side as well as the operating cost side. And on the capital side, as Steve mentioned in his remarks, we're well on our way to achieving our targets. We're about halfway home on the capital side. And on the operating expense side, which is where our field people really do come into play, and very important that those folks that are closest to the well had embraced this, they really have. I mean, we're actually more than 50% toward our goal on the operating expense side, more like 2/3 of the way there. And it's across a lot of different categories. Just top to bottom, not just one specific thing.

I'd like to go back, Doug. I mean, the goal here is not just cutting the costs, but making more margin. And so it isn't just about you cut the cost by closing down a facility or something, but the goal is creating more margins, so, so far, we haven't seen any reduction in our production as a result of this.

Your next question comes from Evan Calio of Morgan Stanley.

It's actually Drew Venker. I just wanted to ask you guys there's been a number of shareholder initiatives in the past few months targeted mainly at option companies revolving around separating business lines to boost valuation. So 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 hate to use the bad word, but integrated with our mostly Permian operations. And we believe that our oil company gets better prices for the product, the oil. And putting it in a form where some third party shared in that may not be the best thing to do. Chemical companies -- this is a chlorine and caustic business -- chemical companies as a [indiscernible] group don't generate huge multiples. So I mean, there's other things people could talk about doing that -- and we look at all this stuff regularly to see whether there's real value here that could be created. So both Ray and I are large shareholders in the business. We're not here to collect salaries. And so from our perspective, most of our net worth, or at least I'll say it for me, is tied up in this. So from our perspective, we're perfectly aligned with the shareholders in this. And our goal is to make the shareholder -- the stock go up and increase our net worth that way rather than through 5% increase in our salary or something. So I think that -- I think we're perfectly aligned. A lot of people I know in the business don't have a lot of stock, but we're perfectly aligned on this and we continue to look at things that make sense that will increase value. But those 2 segments are small compared to the total and so -- but I'd be very cautious about the midstream because it's so heavily integrated into our margins in the Permian. Because one of the advantage we have in the Permian is we control our own infrastructure and to be a fiduciary -- you still could control it. Being a fiduciary is not necessarily what you want to be. We can -- Willie -- Willie Chiang who runs that business can maybe talk about it a little bit.

I'll may make a comment on just the 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. And 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. And as you all well know, when you have constrained supply that's not a good thing. So price signals work, infrastructure gets built and we're able to match supply with demand and get access to other markets. And I think to do that without control in a midstream company is a little more difficult, but we see it as a real, real advantage that we have.

Your next question comes from Doug Leggate of Bank of America Merrill Lynch.

A couple, please, Steve. Steve, on the cost cutting, you signaled earlier this year the competitive conference side of this had been going. But a couple of months ago, when I had the opportunity to travel with you, you also signaled that you've had a 50% increase in cash OpEx between first quarter of '11 and the third quarter of '12. And I suggest 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 '11 cash OpEx numbers 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? And I have a follow-up, please.

Yes, I hate to overpromise here, so I think we'll stick with our current outlook. We've been -- both Bill and I have been surprised and even -- and in Sandy's operations, too. I'm surprised at a lot of the ideas that have been generated. So 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 talked about this forever. When the stock was poor, after the last call we took -- we stepped up and bought a fair number of shares. And had I known it was going to respond so quickly to stock, I would have bought more shares admittedly. But my ability to predict the stock price is modest on a good day. So there could be some of that. There could be higher dividend growth. But the goals are still the same. When the stock price doesn't reflect the reality of the business, that'll be used. And when people get negative about the stock for usually short-term reasons, we'll deal with that. And dividends are important part of the business. So exactly what we're going to do, I don't know. But even with the numbers I've given you, you should understand with the numbers of the cash from operations less the capital, there's $3.1 billion of difference and that's really last year's product prices. And that, I think I've been reasonable, if you will, in figuring that number out. So I think that with the dividends taking a little more than half of that, it still leaves a fair amount left and I would expect over time that number will widen. The Al Hosn project, which if somebody asked about it, we'll get Sandy to talk about it, the Al Hosn product is going to add a lot of cash flow to the company and obviously reduce our capital spend. So as we look forward to 2015 and late 2014 maybe, but 2015 for sure, company's cash flow will grow. We can't treat our business the same as the small producer. Small producer takes all his money and drills wells with it. So his current production may look a little better. But 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 and you suffer a little bit now. But on the long run, these are things that build the company out. So if that answers your question.

That was a very long answer, but yes, it answered. My follow-up will be a little quicker. The transition to a little bit more conventional drilling in California, I guess this is kind of a bread-and-butter exploration you guys talked about a couple of years ago. Can 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.

It's a slight shift actually. It's not a huge shift. The program -- one of the issues we had -- I had really last year was that as we tried to boost the program, we couldn't really -- we counted on being able to drill. And if we didn't get the permit or whatever, you wound up with a fair amount of rig inefficiency because you couldn't drill the rig. You couldn't the well. You had to find some other location for the rig. So we 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. But I think right now, we want high certainty, good returns and that's what we're doing in California and in the Permian. So I mean, that's really the goal of this year. And if we see better opportunities later on, we'll do that.

Your next question comes from Ed Westlake at Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: 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 and forget the revisions, if you just look at the program and the overall finding and developing cost of program, once you see those numbers, you haven't seen them yet of course, you'll see the $17 is very close to what we're doing worldwide. And when Al Hosn comes on, the depreciation expense per BOE is going to fall for the company so -- because you're going to get low depreciation barrels. So 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. And I think that this is -- you don't really know, of course, but we're very close here. So I think we had 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. And so I think that -- and some additional chemical earnings from the new plant. So I think our overall cash from operations and earnings will get better, but I think we're close here on the DD&A. I don't think there's not really much more -- and we've taken out some -- in the charge, we took out some of the things that were a drag on it. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And then shifting to the Permian, Permian capital is flat. California capital is down. I think from the presentation you released earlier this year, the net share of Permian acreage is increasing. So could you just give us an update on sort of the rig program that you planned actually in the Permian and maybe some of the EURs and rig cost that you're seeing in the horizontal program in particular. And I guess, a follow-on would be how much production you think you'll get from the acquisitions that you made in 2012 and '13?

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 5,000 surely. 3,000 or 4,000 a day, I would guess by the time we're through. And we picked up a little gas in California. I did sell forward or whatever the form of art [ph] is for that, the gas that we bought at the lower $4 an Mcf for 15 months, so we get about 1/3 of our money back in the 15 months that we put into it. So in that basis, a reasonable cost. And 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. And roughly 1/3 of that program will be in the Wolfberry, which we've spoken to you about in previous calls. Another 1/3 is going to be mainly in the Delaware Basin. And then the remainder will be centered around several other anchor-type programs. And 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. But 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. Edward Westlake - Crédit Suisse AG, Research Division: So that's 5-0 or 15, sorry?

I meant to say 15. Edward Westlake - Crédit Suisse AG, Research Division: He has new target now. Great, okay.

No, it's 15.

There's some guy in the Permian who just had a heart attack.

Your next question comes from Leo Mariani of RBC.

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.

Yes, Leo, really not so much. Only about 15% to 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. And 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, will you expect that to pick back up later in 2013? Just any color you had around that would be helpful.

Yes, we've already seen some sizable, actually reductions in the costs, but we're not where we need to be. And so we're going to continue to drill at a moderate rate there and see what goes on. But we're down to sort of all right numbers. And of course, the product price is now better there than it's been. So -- but I think we'll hold this level -- we'll 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 spent on moving rigs around. So 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 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, then 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. And 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. But nothing exactly on the horizon in 2013. Middle East should be viewed -- I view it like the Permian in 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. Then, 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 because 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.

Your next question comes from Paul Sankey of Deutsche Bank.

On the volumes, Steve, in the past, you talked about 5% to 8% at a global level. This may be an unnecessary detail, but it's not a number that you -- you haven't put out a total volume target. I'm not sure it particularly matters, but I guess implied you would be a kind of a 5% company level growth for next year. Is there any particular reason that you're not specifying that 5% to 8%?

Yes, there is. The target still exists, let's not argue, but the target's there because if we grew about 5% last year and if we look ahead to the Al Hosn project going on, you'll be -- for the multiyear 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. And so it's really about the U.S. gas and that's the only thing that I view as -- and that's why we're not -- I wish you guys would stop talking about BOEs or at least convert it 25 to 1 or something. But 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 designed to be conservatively estimated. The gas is just hard and so that's why we're staying away from the BOE sort of calculation. But 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 could do that, to make some BOE numbers. But I mean, the money right now is in oil, I mean, black oil. I don't mean NGLs. And so that's why we're doing it.

Yes, perfectly understood. In the past, you've also been -- you're frank about how difficult it is to forecast the gas number. You said the same thing about the international volumes. How confident -- I mean, within ...

No, just Iraq. The reason in Iraq is we don't know what the capital is because it's not in our control. I mean, there's another operator there, so if they spend more money, you'll get more production. And if they spend less, you'll get less production. But 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 6 months. So it's sort of -- and that's the number that I -- it's not in our control. The things that are in control we could 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. And so you can wind up a lot more or fewer barrels in Iraq depending on what they spend. Nobody should be bothered by that really, but it's not something -- it's like gas decline and not something I can estimate. But it's even more out of our control because it's a third-party operator operating in a difficult environment.

Yes, I totally understand. On acquisitions, you talked about transitioning to an organic -- 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, it was $2.5 billion. Can you talk a bit about where acquisitions will fit in, in 2013, again best guess?

It just depends -- we can't create acquisitions. Somebody has to want to sell. And at the end of last year, for tax reasons or whatever, we had to rush people in the fourth quarter. So if you want to run a lot of acquisitions, you ought to go to people in Washington and talk 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 our -- we've got a full program when we can manage of acquisitions right now, especially capital-intensive ones, which is almost all of these are now are not a high priority.

Yes, and disposals. What about the Bakken?

Well, anything that adds value, we would look at. Bakken is a -- if costs were a little better and it's a place where there's a lot of oil in the United States. The differentials have gone away, but if somebody liked to buy my desk and they pay the right price, they're more than welcome to it. There's not much in the drawers.

Great. And then just finally for me, if I could while we got Willie Chiang there as well. You referenced that the Midland differentials, but 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'd 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. But at the same time, you're adding more pipeline capacity to further avoid any risk of -- how should we kind of put all of that together?

Yes, we'll let Willie answer that.

Paul, I think if you look at the infrastructure in the industry right now, industry is -- the infrastructure has lagged the prices signals. Price signals haven't been there. People haven't built out. We all wish we would have built more infrastructure earlier. We don't deal only with the Brent-TI spread. We also have the Midland, the Cushing spread. And so 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 in some pipeline on maintenance. So again, we're trying ...

I guess my question was -- sorry, I was just going to interrupt and just say that so the point is that you did suffer from those differentials?

Oh yes, yes.

We didn't suffer much, that's true.

Okay. Keep going, Willie, sorry.

Well, my point is, yes, by putting more infrastructure in and making sure we have access in different markets. I think going forward you should see that we won't get as impacted with any of these abnormalities between -- the basis difference between regions.

Right. And then finally, Willie, I guess you expect LLS prices to be pressured down and Permian prices to rise in some combination. What is your thoughts? And I'll leave it there.

I think there's a lot of other people kind of looking at LLS prices in 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.

Your next question comes from Matt Portillo of Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick questions for me. In terms of -- 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 kind of the incremental capital or the incremental free cash flow may go to dividend increase? And so just trying to understand how you guys are thinking about that relative to the historical growth rate, and should we expect the potential 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 really mine -- not my decision to make. Everybody here is committed to dividend growth and exactly what it'll be just depends. It just depends on how predictable it is. It also depends on the stock price to some extent. If you get downward movement in the stock price, we may shift some more money to buying in some shares. So you should expect double-digit growth in the dividends going forward, but whether we know exactly what it'll be in any one year is hard to say. But I think as we look through this whole process in the next 2 or 3 years, we ought to see increased free cash flow and the ability to pay higher dividends. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then 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 more 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?

Yes, I think the Mid-Continent had some performance issues in some of the gas reservoirs, which we -- that way. And then there's an old reservoir in old Elk Hills which underperformed. I think those are the 2 major areas where there was performance revisions.

Your next question comes from Faisal Khan of Citi.

Just a few questions. You mentioned before that you had a high level -- high number of contractors earlier in the year and that part of the cost-reduction effort was getting, removing some of those contractors from the cost structure. Can you give us an idea of what the number of contractors where at the beginning of this cost-reduction effort and where they are today?

Contractors are 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. And the numbers, I think...

It's in the hundreds.

Yes, hundreds of them, how many of we let go.

That's how many we've let go, Steve. It's in the high hundreds.

High hundreds. And that's maybe 20%, 25% of what's there. But these aren't the contractors like the Haliburtons out. This isn't work over -- guys doing work over. These are guys primarily in the offices.

And is there more of these kind of cutting to go or is there -- you think you're kind of done at this point with this part of the cost structure?

You're never done looking at costs. It's like 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 and then you go look at it again. These are -- you take the things that you know you can handle first and then you move down the road. Getting done with looking at costs, it just never happens. So nobody really -- there's no plan that says every month you're going to fire 100 contractors or something. It just -- we're trying to do it in a way that's not done with a meat axe but with a scalpel.

Okay, understood. And on the reserve additions, I think previously you had not booked anything for the Shah gas project. And 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.

And how much -- was it a big part of it or...

Yes, it was. 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 the spending. We've only booked maybe 1/3, 40% at best of the reserves and we spent -- Sandy?

We spent about 70% of the money.

So we're pretty far behind booking relative to the spending. So you should expect to see more additions over the next 2 or 3 years. And really beyond that as the project matures and there's more opportunity for gas delivery, I think you'll see a lot more additions. So 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. And then on the $2.5 billion of acquisitions you made this year, how much production did that add to your portfolio during the year? In what geographies or how much acreage did you guys pick up in those $2.5 billion?

I don't really know. Most of it was done in the fourth quarter, so it didn't add anything. So you picked up a little bit in the early part of the year, but virtually, all of -- nothing really of a few thousand barrels a day maybe in the last year. But almost all of the production basically closed at the end of the year. So last year was sort of nothing.

Okay. And was this mostly centered in the Permian or also into 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. And 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 find something in South Texas maybe that adds to what we have, but those tend to be pretty small.

Okay. And then on your production growth guidance, for domestic oil volumes, the 11% -- 10%, 11% sort of number that you have out there, is that -- I take it that's also mostly -- most of that growth is coming from the Permian, or what's the -- what do you expect California to contribute to that growth?

No, no, no. The oil production will come from Permian and California, both, and maybe a little out of the Bakken even. But I mean, that's -- we're spending the money in the Permian so that's what you're going to see it. But we're also spending a fair amount of money in California and again they're focused on oil drilling. Our California oil production, as we get through -- as we head into '14, will grow sharply as some of these steam floods and other things start to come on. So once we get through the permitting phase of that activity, you'll see some more volume, oil volume growth, into '14 and '15.

Your next question comes from Roger Read of Wells Fargo.

Just a quick question for you. As we look at the Permian Basin and the view of relatively, let's say, as a percentage compared to the industry low horizontal drilling, what is it you need to see out there to get more aggressive on the horizontal side? Is it strictly a cost-per-well issue, is it the decline rates that continue to hold you back? I mean, 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. So our program is a balance of all those activities. And so it's designed to make a sustainable program, not one that gets a big, big, big level right off.

Well, I understand that. But if you're looking at it, and I know you look at your overall portfolio from very much the return criteria, I mean, if the returns were the same for the horizontal wells or potentially even better, would you move more aggressively towards that? Or is it the decline rates and the year-over-year comps have become tougher that keeps you from ...

We'll let Bill answer. He knows more about it than I do.

Roger, really what dictates an increase in horizontal drilling is the reservoir and the targets 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. So really, what dictates it more than anything is the target.

Okay. So that kind of falls into my next question. I mean, 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 look 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. But as I said before, 1/3 of our program is in the Wolfberry, which is vertical drilling essentially. And another 1/3 is in the Delaware Basin, which, again, is largely driven by vertical drilling. So as some of these unconventional plays mature, then I think you'll see a little bit more in the way of horizontal holes in those reservoirs.

We're not -- 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, cutting through it. While other people have maybe less acreage or less opportunities, they're basically into this and we'll learn from them and we'll begin some of their wells because of our large position rather than go and be the experiment or 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 1 year old or 18 months old when you have huge decline, initial decline rates, is very difficult and we tend to be fairly conservative of how we look at it because we don't know how it's going to flat -- how the curve is going to flatten. And that's maybe just us, but we can afford to wait, be patient and thoughtful about this. And we're maybe less convinced than other people about the ultimate recovery. But we'll find out here in the next year or 2 as these plays mature and our position is good enough that we can do that.

Your next question comes from Eliot Javanmardi of Capital One.

I think many of the questions have been asked already, but I did want to ask you one more. You had mentioned that it looks like you're now 2/3 of the way through your cost-cutting goals. I just want to get some clarification around what number we're looking at to start with and where that -- and what number we're trying to end with just from a clarifications standpoint? Could you help me out there?

Bill will answer that.

I mean, on an absolute dollar basis, Eliot, we're looking at $450 million to $500 million of reduction in absolute OpEx. That's on the domestic side.

Okay. And what was the time frame to meet that target? It was mid-year or for '13 or...

That's an overall average target for 2013.

Okay. So your 2/3 ...

So as you think about it, it's a little less than the beginning and so the exit rate will be different, it will be higher. Otherwise, you won't make the average.

Your last question comes from John Herrlin of Societe Generale.

Couple of quick ones. With the cost savings, it's all the Oxy initiatives, no help on the services side at all?

Very little, but we're starting -- we're not ignoring that. But right now, it's really all within our power. And we're not planning that, but there's clearly some out there. So we would hope to get some from that, but what we're planning on is what we could do within our control.

Okay. With the Elk Hills plant, is that now fully operational? Are you running it full?

Yes, and you can see how it's generating more NGLs. As for the gases you can't see it exactly. But the gas is down at Elk Hills. But the equivalent amount of BOEs were converted into NGLs. So even though we're getting good -- not good gas prices but relatively good gas prices in California, you get better prices for NGLs.

Thanks very much for joining us today. And should you have further questions, please call us here in New York. Thank you.

Thank you.

Thank you. This does conclude today's conference call. You may now disconnect.