Occidental Petroleum Corporation (OXY) Q3 2012 Earnings Report, Transcript and Summary

Good morning. 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 Third Quarter 2012 Earnings Release Conference Call. [Operator Instructions] Mr. Stavros, you may begin your conference.

Thank you, Christie, and good morning, everyone. Welcome to Occidental Petroleum's Third Quarter 2012 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Stephen 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; and Sandy Lowe, President of our International Oil and Gas Business. In just a moment, I will turn the call over to our CFO, Cynthia Walker, who will review our financial and operating results for this year's third quarter. Steve Chazen will then follow with comments on our strategy, progress, as well as providing some guidance for the remainder of this year. Our third quarter 2012 earnings press release, investor relations supplemental schedules and the conference call presentation slides, which refer both to Cynthia's and Steve's remarks, 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. Income from continuing operations was $1.4 billion or $1.70 per diluted share in the third quarter of 2012, compared to $1.8 billion or $2.18 per diluted share in the third quarter of 2011 and $1.3 billion or $1.64 per diluted share in the second quarter of 2012. The third quarter income from continuing operations improved by $0.06 per diluted share from the second quarter of this year. The improvement reflected higher margins in the marketing and trading businesses, partially offset by lower earnings in the chemical segment. In the oil and gas business, the effect of higher liquids production and domestic gas prices was partially offset by the impact of a 3% decline in realized worldwide crude oil prices. Now let me turn to the segment breakdown for the third quarter. In the oil and gas business, earnings for the third quarter of 2012 were $2 billion, compared to $2 billion in the second quarter of 2012 and $2.6 billion in the third quarter of 2011. Overall, third quarter 2012 production was 766,000 barrels per day, flat with the record set by the company in the second quarter of 2012, and up 4% from the third quarter of 2011. Our domestic production was 469,000 barrels per day, an increase of 7,000 barrels per day from the second quarter of 2012, and most notably, the eighth consecutive quarter of domestic record volume growth for the company. Production was 8% higher in the third quarter of 2011 -- versus the third quarter of 2011. Almost all the sequential quarterly increase came from the Permian and Williston basins. California production was higher in liquids, but flat on an overall BOE basis with the second quarter, mainly due to lower gas volumes associated with initial startup issues of the new gas plant. These issues were resolved mid-quarter, although the positive effect of the plant on overall third quarter production was muted as a result. Today, the plant continues to run as expected, and California's current production run rate is approximately 150,000 barrels per day. In Latin America, volumes were 32,000 barrels per day. And in the Middle East, volumes were 265,000 barrels per day. I'll note meaningful sequential changes in Qatar production, however, details regarding other company-specific production levels are available as usual in the investor relations supplemental schedules that we provide. Dolphin's production was 13,000 barrels per day lower than the second quarter, resulting from the full cost recovery of pre-startup capital, as we noted to anticipate last quarter. Qatar's production was also impacted by a facility outage in August, which reduced production in the quarter by about 5,000 barrels per day. The outage was subsequently resolved. The rest of the Middle East partially offset these decreases in part due to higher spending levels. Factors affecting production sharing and similar contracts, including oil prices, did not significantly impact the quarter's production volumes compared to the third quarter of 2011 or the second quarter of 2012. Third quarter 2012 realized prices were mixed for our products compared to the second quarter of the year. Our worldwide crude oil realized price was $96.62 per barrel, a decrease of about 3%. Worldwide NGLs were $40.65 per barrel, also a decrease of about 3% from the second quarter, while domestic natural gas prices were $2.48 per million cubic feet, an improvement of 19%. The change in worldwide crude oil realized price was primarily due to the mix of sales volumes in the quarter. Third quarter 2012 realized prices were lower than third quarter 2011 prices for all of our products. On a year-over-year basis, price decreases were 1% for worldwide crude oil, 27% for worldwide NGLs and 41% for domestic natural gas. Realized oil prices for the quarter represented 105% of the average WTI price and 88% of the average Brent price. Realized NGL prices were 44% of the average WTI price and realized domestic gas prices were 90% 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 approximately $36 million, and $8 million per $1 per barrel change in NGL prices. A change of $0.50 per million BTU in domestic gas prices affects quarterly pretax earnings by about $35 million. These price change sensitivities include the impact of production sharing and similar contract volume changes on income. Oil and gas production costs were $15 per barrel for the first 9 months of 2012. This is compared to $12.84 per barrel for the full year of 2011. The cost increase reflects higher well maintenance activity, in part reflecting our higher well count, higher workover activity and higher support and injection costs. Taxes other than on income, which are generally related to product prices, were $2.43 per barrel for the first 9 months of 2012, compared to $2.21 per barrel for the full year of 2011. And third quarter exploration expense was $69 million. Now turning to the chemical segment. Earnings for the third quarter of 2012 were $164 million (sic) [$162 million], compared to $194 million in the second quarter of 2012 and $245 million for the third quarter of 2011. Both the sequential quarterly and year-over-year declines were due to lower Asian market demand that drove export prices lower, partially offset by lower ethylene costs. In the midstream segment, earnings were $156 million for the third quarter of 2012, compared to $77 million in the second quarter of 2012, and as well in the third quarter of 2011. The 2012 quarterly increase in earnings was in the marketing and trading business primarily and power generation, partially offset by lower margins in the gas plants, reflecting lower NGL prices. Our worldwide effective tax rate was 38% for the third quarter of 2012. The lower rate compared to our guidance was attributable to a shift in the mix of income towards more domestic. Our third quarter U.S. and foreign tax rates are included in the investor relations supplemental schedules. In the first 9 months of 2012, we generated $9.2 billion of cash flow from operations before working capital changes. Working capital reduced our 9 month cash flow from operations by approximately $660 million to $8.5 billion. Approximately $510 million of the working capital use occurred in the third quarter. Capital expenditures for the first 9 months of 2012 were $7.7 billion, of which $2.6 billion was spent in the third quarter. Year-to-date capital expenditures by segment were 82% in the oil and gas business, 14% in midstream, and the remainder in the chemicals business. Acquisitions for the first 9 months of 2012 were $1.2 billion, of which $100 million was spent in the third quarter. Financing activities, which include dividends paid, stock buybacks and a $1.74 billion borrowing earlier this year, provided a $300 million net cash inflow for the first 9 months of the year. These and other net cash flows resulted in a $3.8 billion cash balance at September 30. The weighted average basic shares outstanding for the first 9 months of 2012 were 810.1 million, and the weighted average diluted shares outstanding were 810.8 million. Diluted shares outstanding at the end of the quarter were approximately 810.1 million. And lastly, our debt-to-capitalization ratio was 16%. Copies of the press release announcing our third quarter earnings and the investor relations supplemental schedules are available on our website at www.oxy.com or through the SEC's EDGAR system. At this time, I'll turn the call over to Steve Chazen to discuss an update on our strategy, our operations and also provide guidance for the fourth quarter of the year.

Thank you, Cynthia. Oxy's domestic oil and gas segment produced record volumes for the eighth consecutive quarter and continued to execute in our liquids production growth strategy. In the third quarter, domestic production of 469,000 barrel equivalents per day, consisting of 334,000 barrels of liquids and 812 million cubic feet of gas per day, was an increase of 7,000 barrel equivalents per day compared with the second quarter of 2012. The increase in domestic production over the second quarter of 2012, almost entirely in oil, which grew from 249,000 barrels a day to 260,000. Gas production declined 28 million cubic feet of gas per day on a sequential quarterly basis, mainly in California, some of which was due to the initial startup issues of the new gas plant that Cynthia mentioned. Compared with the third quarter of 2011, our domestic production grew by 8%, or 33,000 barrels a day, of which 30,000 a day was oil production growth. Our annualized return on equity for the first 9 months of 2012 was 15% and return on capital employed was 13%. As we near the end of 2012, I want to take this opportunity to reflect on our strategy, our progress and our future. As a company, we continue to have 3 main objectives: Generate rates of return on invested capital significantly in excess of our cost of capital, achieve moderate growth of the business and deliver continued dividend growth. With regards to returns, we don't believe that a depleting or shrinking business or selling profitable future opportunities to fund high-decline production can yield high rates of return. One can reduce spending to achieve short-term higher returns, but these returns would not be sustainable as the company would deplete. Our business model is to balance the need for growth of the business, while maintaining attractive returns. We are currently in an investing phase in many of our businesses, where higher-than-normal portion of our capital is spent on longer-term projects. This year we expect to spend approximately 25% of our total capital expenditures on future growth projects that will contribute to our operations over the next several years. These expenditures include: Capital for the Al Hosn Shah gas project, which we expect to start production in late 2014; capital for gas and CO2 processing plants and pipelines to maintain or expand the capacity of these facilities to handle future production increases; part of the capital for the chemical segment and other items. In our oil and gas business, we have built a portfolio of assets that allow us to execute this strategy. Domestically and internationally, we have a business mix of both higher return assets and higher growth assets. Importantly, many of our higher growth assets are relatively early in their development, although we have already experienced meaningful success. In the U.S., our Permian CO2 operations continue to be our most profitable business, generating the highest free cash flow after capital among our entire portfolio of assets. In contrast, our Permian non-CO2 business is one of the fastest growing assets in our entire portfolio. Since we've began significant delineation and development efforts in late 2010, we have grown production by over 25%. As a result of the significant activity by us and our partners, our Permian acreage, where we believe resource development is likely, has grown from our estimate of about 3 million gross acres earlier in the year to about 4.8 million acres in October. Oxy's share of this acreage grew from about 1 million acres to about 1.7 million acres during the same period. The attached conference call presentation slide shows our current acreage position in the Permian. In California, we have a very large acreage position with diverse geological characteristic and numerous reservoir targets. As a result, development opportunities range from conventional to steam floods, to water floods and shale drilling. The drilling cost and expected ultimate recoveries also vary for each area. In mid-2010, we shifted our development program to conventional and unconventional opportunities outside the traditional and more mature Elk Hills areas. As a result, we have experienced strong production growth in these new areas, although traditional Elk Hills had experienced some decline. As you can see on the attached conference call presentation slide, traditional Elk Hills production dropped from 41,000 barrels per day in the fourth quarter of 2010 to 37,000 in the third quarter of 2012. Liquids production growth in the rest of California more than offset this decline during the same period, growing from 49,000 barrels a day to 69,000. Traditional Elk Hills gas production declined from 22,000 equivalent barrels per day to 19,000 during the same period, which was mostly offset by an increase in gas production in the rest of California from 21,000 equivalent barrels a day to 23,000. Recently, we further modified our programs to emphasize oil production in light of depressed gas prices and associated liquids. As a result, gas production in all of California declined in the third quarter of this year. Total California growth on a BOE basis is slower than we thought it would be, in part due to the higher-than-expected declines at Elk Hills, permitting issues, and more recently, low gas prices. On a positive note, overall performance of the new resources has been consistent with expectations, including our unconventional opportunities, for which well performance is similar to the type curves we showed you a couple of years ago. I would also note that over the last several years, we spent $370 million on the new Elk Hills gas plant. The plant went into operation in early July and, not withstanding initial startup issues, is positively affecting our operational efficiency and production, including higher liquids yields. The plant operated optimally for about 1 month in the last quarter and has been operating as expected since. We will continue to focus on higher return, low-cost opportunities in California, and as I mentioned, this is a very diverse opportunity set. For example, one of the projects we haven't talked about much in the past is a major steam flood project in Lost Hills. We expect to achieve significant production growth, about 15,000 barrels a day in several years, from the current 4,000 barrel a day rate. Total oil in place is estimated to be about 500 million barrels. Using reasonable assumptions, we expect to recover over 50 million barrels net to Oxy. Our drilling cost in this area average in the low $200,000 per well, and we expect to bring this average cost down over time. In the Williston basin in North Dakota, we currently have over 310,000 net acres of significant resource potential, which we estimate to be about 250 million net barrels. Our production in the basin has tripled since we entered the area over 1.5 years ago. We have recently slowed our drilling activity and significantly reduced our rig count in the basin as a result of cost pressures. While well costs have subsequently declined modestly, we will only increase our rig count when costs come down enough to make returns competitive with the rest of our portfolio. We believe that over the long term, our resource base in the Williston basin represents a significant opportunity for the company. In the Mid-Continent, including our assets in South Texas, we have significantly reduced our gas drilling. However, we could ramp up our gas production rapidly and meaningfully if prices for gas and liquids improved from their current level on a sustained basis. Internationally, our most significant businesses are in the Middle East region, where our operations are characterized by limited duration contracts with high rates return on invested capital during the contract term. Our primary focus in the Middle East is United Arab Emirates, Oman and Qatar, which includes Dolphin. Most of our international capital is allocated to these countries, and we derive a very substantial portion of our international earnings and free cash flow after capital from Qatar and Oman. Going forward, the UAE, where we are developing the Al Hosn gas project, is also expected to make a significant contribution to earnings and free cash flow. The Al Hosn gas project is approximately 61% complete and is progressing as planned. The project made up about 11% of our total capital program for the first 9 months of this year. While capital spending is running higher for 2012 than our initially anticipated levels, total development capital for the project is expected to be in line with previous estimates. Currently, the Al Hosn project is consuming sizable amounts of capital during its development phase. We expect to see a significant shift in late 2014, when the project changes from being a cash consumer to a cash generator. Once the project becomes operational, early free cash flow should generate -- should be approximately $600 million annually at roughly current oil prices and conservative sulfur prices. The project has the potential for additional production in later years, which would significantly increase its cash flow. We're going to spend approximately $1.2 billion on the Al Hosn project this year. Once the project becomes operational, our free cash flow should increase by the difference in the capital -- between capital consumption and generation. Based on our 2012 capital spend for the project, this would equate to a $1.8 billion increase in our annual cash flow. Lastly, we are focusing on improving our returns through a comprehensive effort to reduce operating expenses and improve capital efficiency. As we indicated in the past, our operating costs have been increasing for some time for a variety of reasons: including industry inflation; our desire to take advantage of high product prices by accelerating production through workovers, which pay for themselves over a short period of time; and our recent rapid growth, which has caused some short-term inefficiencies. We are embarking on an aggressive plan to improve our operational efficiencies over all cost categories, including capital, with a view to achieve an appreciable reduction in our operating expenses and our drilling cost to at least last year's levels. We believe that we will start seeing the benefit of this plan clearly in the first quarter of 2013 and achieve last year's cost levels by the end of the next year on a run rate basis. Several initiatives have already begun, and we are seeing good early results. For example, during the third quarter, we reduced our drilling cost by over 15% in parts of Elk Hills. Our goal next year is to reduce U.S. well costs by about this amount. I will now turn to guidance for the fourth quarter. Our fourth quarter capital spending will slow from the third quarter level to a run rate that we believe will be in line with next year's total capital program. Our intention was to reduce capital spending meaningfully starting in the third quarter. However, this would have resulted in inefficiency in areas where we were seeing positive results, such as the Permian, parts of California and Oman. As we discussed in prior quarters, we are sharply reducing our pure gas drilling and have more recently cut back our drilling in certain liquids-rich areas as well. We are also in the process of eliminating our less productive rigs to improve our returns. Our focus on much higher-return oil drilling will result in a decline in our gas, and to a much lesser extent, NGL production in the future. Turning to production expectations in the fourth quarter. Over the last year, we achieved our goal of increasing domestic production by 6,000 to 8,000 barrels equivalent per day quarter-over-quarter. We expect our fourth quarter oil production to grow by about this much. However, the expected decline in gas production, resulting from the change in our capital program focus I discussed earlier, may offset some of the increased oil production on an equivalent barrels per day basis. Internationally, at current prices we expect production to be approximately flat with the third quarter, while sales volumes will increase slightly. We expect fourth quarter exploration expense to be about $100 million for seismic and drilling in our exploration program. The fourth quarter is typically the chemical segment's weakest quarter. We estimate fourth quarter earnings will be about $140 million, or slightly lower than the third quarter. Along with seasonal factors, weak global demand from the European and Asian economies and rising natural gas costs will keep pressure on the margins. We expect the worldwide tax rate for the fourth quarter in 2012 to increase to about 40% to 41%. In closing, we believe that we have a deep portfolio of development opportunities that will allow us to continue to deliver returns that are 5 to 6 points above our cost of capital. Total return to our shareholders is a combination of appreciation in stock price and dividends. We have long believed that the job of management is to convert earnings that are retained into stock market value. For example, if we retain $1 billion, we should be able to give the shareholders at least $1 billion increase in the market value of the company. Historically, we have generated closer to $1.5 in value for each $1 kept. This is a challenging proposition over time as the company continues to grow. An old Wall Street maxim is that, "The market is a voting machine over the short term, but a weighing machine over time." We hope that this is true, as we firmly believe that our program of investing in a longer-than-usual, for us, timeframe will reap rewards for our shareholders. If for some reason, our investment plans do not generate acceptable stock market results over the next few months, we will return more of our retained earnings to our shareholders. We have increased our dividends at a compounded rate of 15.8% over the last 10 years through 11 dividend increases. We expect to increase our dividends again next year and in the future at a rate that would maximize return to our shareholders. I think we're now ready to take your questions.

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

Your emphasis on returns on capital was pretty clear from today's comments. And on this point, I wanted to better understand the point about achieving 2011 cost levels by the end of '13. First is, is that the correct interpretation? And if so, does that imply the pretax cost savings will be above $1 billion, maybe $1.5 billion? And if so, are there some specific compartments from which those cost savings will emanate that you can highlight to us today?

Yes, there's 2 elements of the cost saving. One is operating cost. And I think it's fairly straightforward to take the current $15 rate and subtract from last year's number and multiply by 275 million barrels, which is roughly the annual production. That will give you an idea of sort of the savings. I hope to beat that, frankly. We should be able to, but I think that's what we're going to say for now. There may be some G&A savings too, but we haven't really baked that in. On the capital, I think it's fairly straightforward to say that the capital program for the U.S. business, if we say 15% on wells, the capital for the U.S. business will decline sort of by that amount. So with the cash flow savings, you're right about where that will be. We may decline the U.S. business by more than that, frankly. But it just depends on how well they're converting dollars into returns. We can delay drilling where the returns aren't as good as we would like, and I'm going to be more aggressive in the capital program than I've been in the last year. So a lot more negative feedback to the unit. So I think you should look to lower capital levels next year for the U.S. business. International business is a little more complicated because a lot of that's really not in our control, but similar levels. About the only increased area I see is in the midstream, where we're going to build a pipeline from our gathering system and our pipelines in the West Texas to the Houston area, and that will cost us about $400 million. And we hope to capture a fair amount of the differential and improve our returns that way. But we're going to focus a lot more starting this quarter but in the quarters ahead, on improving the returns and translating more of the volume growth into profits.

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

Steve, I've got a couple, if I may. The first one is really on your very last comment about -- I don't want to paraphrase you too badly here, but if your current strategy doesn't translate to shareholder returns or better shareholder return to the share price, I guess, you're going to take a different track. Can I just ask you to elaborate on that a little bit, because obviously, there has been, as you're well aware, material underperformance of the stock. And I'm just wondering how tolerant you're going to be of that on a go-forward basis before...

Not too tolerant, I think is the short answer. I don't know whether -- I don't know the form it will take. But dividends are the easiest form because that way everybody knows. They actually get the check. If the stock is trading at crummy levels, there'll be more emphasis on share repurchase than we've done historically. But my tolerance level is modest. If we don't see -- if I don't see real improvements in the returns in the next couple of quarters, strategy will change.

Got it. My follow-up is really, as you're well aware there's been a fair amount of -- I'm not going to call it misinformation, but there's been a lot of questions on, specifically, around the California assets, given perhaps the fact that you haven't given a lot of disclosure. I'm curious, when you talk about reallocating capital, if your type curves are still per your presentation in 2010 and your liquids mix is as per your presentation and of course, your costs presumably, are down, and now you've got the gas plant, I could go on and on and on about all the things that have lined up here. It seems to us anyway that those have got to be some of the more compelling returns in the portfolio. So I'll just ask you to explain, why are you not getting after that a little more aggressively, now that you've got the gas plant in place, the cost down and so on, and accumulated permits in place? And I'll leave it at that.

Yes. The permitting process, well, is working pretty well in the fields, that is the existing fields. Extending beyond the fields is still slow. And so, and some of the plants -- there's some air quality permits that are slow in coming. The permitting process is a lot better, say, in Elk Hills field or Buena Vista field or some of the other fields. Outside of the field, it's still slower than it used to be. The only way I can assure that there's -- getting the squeal out of every dollar that they spend, is to tighten their capital, rather than give them more money. And so they will probably suffer less in the capital tightening, but they can still take their costs down considerably. And the more capital -- I don't know how to say it, but discourages prudent spending. So I think their capital program will not be as affected as some others, but will still be affected some. And there are clearly some efficiencies that are needed there. I think they're operating costs are way too high, and they need to bring their operating cost by a whole bunch. And I understand that -- and to some extent, I'm pushed and pulled. I got half the shareholders think I should spend $2 billion a year on capital, and the other half think I should spend $20 billion a year. So I'm trying to maybe probably unsuccessfully sort of weave our way through that. But I think that -- if this thing doesn't -- if they don't get their operating cost down, which is what I'm most focused on, because that translates immediately to profits, then I'm going to continue to tighten there, and there'll be some other changes there in the business unit. The same thing, frankly, in the Permian, where their operating costs are still too high. And the operating costs affect the profits right away and affects our cash flow right away. The capital affects it over time and our drilling -- we're simplifying our program, we'll be drilling fewer, different types of wells next year, and that should make us more efficient. I think we can improve the capital efficiency a fair amount. But where I'm looking for it is, is in the operating costs because there I can affect it more quickly. And if they don't do it soon, there's going to be widespread changes in the operation.

Let me ask you a very quick follow-up. There seems to be a perception that you've got something, pardon me for being direct, but you've got something to hide in California with your failure to be more transparent. Would you care to address that? And then I'll leave it at that.

Yes, sure. I think the way -- I've tried to think about how to show this. We're effectively the only one drilling in California. So you can't look at somebody else, which is what you can do in the Permian or something like that. We show you the actual -- again this quarter, we take out old Elk Hills and we show you the growth in the other business. That's really the best way to look at the total business. The acquisition program doesn't add much in California because there really isn't any volumes to buy. And so that's growing at a very high rate, and if that were a standalone business, you would think it was terrific. This is the best way to show what's going on. There's really nothing to hide. We aren't drilling as many shale wells as somebody would like. And the reason is, and it goes back to this capital efficiency question, if I could bore you for a second. A shale well has a very high decline rate, maybe 30%, 40% the first year, maybe more. Okay, so I could boost this year's production by drilling a bunch of shale wells. But in order to keep the production flat next year, my capital program has to go up, because I got to drill more wells. I mean -- and so that goes against the capital efficiency that people are looking for, and the free cash flow. So I'm trying to do more conventional drilling, which has a lesser decline rate, to keep the capital from bloating in California, and I don't want it to bloat. There's really nothing to hide, and we show you this number excluding Elk Hills. The disappointment has been at Elk Hills, where the decline rate has been worse than we thought. And maybe the gas plant will make it better, maybe it won't. It's doing fine now, and we'll just have to see. But there's really nothing to hide. I disclosed the Lost Hills numbers for a reason. In some report somebody sent me, I don't know where it came from, the guy estimated that the Lost Hills wells were costing $3 million each. They cost roughly $200,000 each. So either the guy doesn't know anything about California or it was deliberately designed to make the numbers for the total of California look worse. Did somebody think we would drill 120 wells that had a $250 breakeven? So we disclosed that. And if you either take Lost Hills out of the numbers or put the right numbers in there, it doesn't really look so bad. While we could track the number of wells that were in that report, we couldn't track the other numbers that he used. So I don't think there's anything to hide. We've shown you what in aggregate is going on, which is all you really should care about.

Your next question comes from Ed Westlake of Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: I guess I'll try another one on California. And I know that's just because obviously there have been a lot of research reports that may or may not have been correct. So you say that you have to reduce costs before you want to put more assets to work. I mean, is that a concern that you have of the average IPs, they're not as good as you are hoping? I mean, is there any statistical well data you could share with us this morning?

It isn't really the IP rates. The IP rates have actually gotten better. The operating costs has reduced the margins to a point where they're going to overspend on operating costs, and it doesn't make sense to encourage that. And so we're not going to -- with the reductions in the capital program, in the cost of the wells that they say they can achieve, and that they will achieve, they'll be able to drill more wells for the same money, which is the true objective. The leases aren't going anywhere. So that's where -- I'm a steward for this money. I'm not -- the goal is not volume growth per se, but profit growth. And we focused on volume growth and the profit growth sort of went away. So that's not -- and California is a big piece of the total. And you can't change the company without improving California. So for the near term -- oil guys, I think, I tell people this all the time only half jokingly, can only work on one thing at a time. So if you tell them you want volume growth, they'll give you volume growth, but some of the other stuff doesn't show up. And if you say, well, what I want is something else, it's only one thing at a time. So I guess I'm going to have to be more agile in giving them objectives. Maybe I have to give quarterly objectives, not annual ones. But the operating costs that they're running in California doesn't make any sense to me. They were running a lot less, half, 2 years ago. And they need to be back to that. If they do that, they'll have plenty of capital to drill the wells. Edward Westlake - Crédit Suisse AG, Research Division: Great. And then a follow-up on the CapEx side. I mean, this is focused more in the midstream. $1.4 billion, I guess, this year, which is obviously ramped up. Some of that's Shah, some of it's integrity in the domestic business. But as you look at your plans, and I think you said that CapEx will go up next year because you want to build this additional pipe. But is there a year at which that, as you look at the forward plans, that you've done enough of that spend, and it will fall to free up some free cash as well?

I would -- once we're through this pipeline and the Al Hosn project, the spending on the plant will basically end in 2014. It will fall the next year. Because you shift from a plant phase to a drilling phase. So the actual spending on Al Hosn will decline some next year and more on the following year as you go from drilling to building out the plant. I think Chris showed you a picture of the plant in the presentation there. This is not a small plant. So it's going to take -- so spending will decline some on the plant next year, and by the following year, it will be down considerably. And we'll be through with the pipeline next year. It's a 1-year program, really. So that will fall off pretty sharply. Unless there turns out to be -- you should understand that if this arbitrage continues, where you can buy oil in our pipeline system at $85 and sell it on the Gulf Coast at $100, we'll probably spend more gathering other people's oil and shipping it through our lines, and that's -- until we do enough of it that the arbitrage goes away.

Your next question comes the line of Paul Sankey of Deutsche Bank.

Steve, that was very interesting and your words were interesting about, quite specifically, if things don't change within the next few months, which came not long after you had said how the market is a voting and weighing machine depending on your timeframe. Are you saying that if the stock price doesn't improve over the -- relative performance doesn't improve over the next few months, you would essentially radically change the strategy, if you like, the long-term strategy? Or are you saying that if you don't get the cost improvements over the next few months, you would radically change your strategy?

Well, I think we're saying some of each. If the relative performance doesn't improve, then we'll return more money to the shareholders, one way or another.

Relative stock performance?

Relative stock performance. I think it's also useful to note that we have a 75% or so correlation to WTI as a stock, which is a lot more than other people. So to some extent, some of it's caused by the decline in WTI, I think. But putting that aside, the costs are how I intend to make the performance of the stock do better. So you got to say, what's the tool to make it so? The tool is bringing the costs under control and improving the profitability. If that doesn't work, that is to say, the profitability improves and the stock continues to be a dog, then we'll have to rethink the whole thing.

To use your words, that the stock's been a dog over the past year, I'm not sure why you haven't, for example, A, changed the dividend most recently, but B, why there's been so little buyback in the recent months?

The buyback is -- basically when we know what the earnings are, we stop buying back. And so a lot of the decline, for whatever reason, shows up in the month before the earnings call. But buybacks are, as far as raising the dividend, we raise it once a year. And it's, whatever, 16% compounded growth in the dividend over a decade, starting not from 0 like some companies. So I don't know what the complaint would be. But fundamentally, dividends are raised once a year once we -- and it goes with setting the program. So we go to the board, we set the program, we figure how much we're going to spend and we figure out how much the dividends go with it. So it's all done together. I think doing the dividends in a vacuum doesn't give the board the kind of oversight that it should have.

No, I guess my point was that your balance sheet would suggest you could do both. I mean, you could be buying back stock aggressively as well as pursuing the cost.

We could.

Now in the past, you've talked about, I guess this is going to be a pretty obvious answer, but in the past, you said you have a vision of the value of the stock on any given day. And I think what you're saying obviously is that you feel it's poorly valued relative to what you think it's really worth. But again, I still don't understand why the buyback has been so muted, given that.

The buyback is done on a formula basis. And if -- at the current levels, our current levels this morning anyway, when I woke up, you get one set of numbers at higher levels, you basically buy less back. If you look at the -- we don't look at relative performance when we do the share buyback. The share buyback is against absolute value. And so the lower the stock falls, the more shares are bought back.

Right. And then finally for me, it sounds like the action you would take would be a radical, let's say radical, I don't know if that's the right word, financial approach, probably cutting CapEx aggressively, probably significantly raising the dividend, possibly buying back stock. Is there an alternate strategy that would be, for example, to split the company, sell the company, anything in the other direction?

I don't know if anybody's got enough money to buy it.

Then I'll ask about splitting.

Splitting, you got to be -- if you split it, you really have to have assets that would be valued materially differently than the overall. And it's very difficult right now to see -- I don't know what an international business would trade for. So I think that before you go down the splitting the company route, you got to see whether -- you got to see whether you can bring your costs under control.

And the last, very last one for me, would you consider special dividends or do you want to make those a regular?

Regular dividends work better.

Your next question comes from Arjun Murti of Goldman Sachs.

Steve, just kind of following up on that last point there. So if there's the possibility, if the underperformance continues, that you cut CapEx and raise the cash returns to shareholders, I mean, the Al Hosn project, that CapEx is going to be what it's going to be. You've added acreage in the Permian. You've added acreage in the Bakken. You've got a huge acreage position in California. Presumably, it doesn't make sense to just sit on these assets. Asset sales, joint ventures, bringing in others to drill this stuff, is that part of the plan? Practically speaking, what does it really mean to cut CapEx when you've been building up these big acreage positions over the years?

In the poorer performing or the lower opportunity areas, you might think of doing something like that. In the stuff that's got long term, very strong potentially, you don't really want to sell your futures. So but you could cut the cap -- for example, you could cut the capital. We haven't really added much acreage in the Permian. All we're showing you here is that the areas that we think that have resource potential have grown. We haven't really bought the acreage. That's just recharacterizing what we own. You don't know, but you don't really -- if you have stuff that has long-term potential, you don't really want to sell your futures, if you can avoid it. But if you looked and you said, well, okay, for the next -- you could cut the -- the U.S. business, especially long-term leases or ownership outright, you could cut the capital, and then as the Al Hosn project comes on in a couple of years, suddenly you got a $1.8 billion swing, and so you could bring your capital, you could use some of that then. So I view it as sort of a deferral mechanism, rather than just sort of cutting it. But if they can't -- if they can't generate the returns in some of the assets, we might farm some out to people who might operate more efficiently.

Absolutely. So I know you've worked on the organization over the years. And I think it was a couple of years ago, you were pretty honest about -- classically, you guys are an EOR company, not a shale drilling company. You're now kind of, again, going after that same operational execution ability. Do you have to acquire a company that can do this stuff for you? I mean...

No, I don't think so. It was 2 years ago, we had this exact conversation in New York. And I said that, we were shifting the business from a -- for want of a better word, an EOR/acquisition company to something that was more operational and more traditional. And I said that was not going to be easy, and I was right. And we've lowered -- I don't know how to say it, the average experience level, I guess is the politically correct way of saying it, of the people. And so some more mistakes have been made than might otherwise have been made. But I think we're getting there, I hope we're getting there. I'm just in a hurry because I'm older than the average. So it's taken longer and been more difficult to change the organization to operational efficiency. One of the issues we have is, outside the United States, our competitors have names like Shell and Exxon and BP, and they operate differently than a small company might operate. We spend a sizable percentage of our capital on environmental, health and safety issues, similar probably to the percentages that Exxon or somebody like that would in both the U.S. and internationally. The smaller producers simply probably doesn't do that. And so we're never going to be the absolute best, because of the fact we're more environmentally focused than some small producer can be. On the other hand, we can be a lot better than we are. And it's been more difficult, there's no question about it, and it's come -- I knew it would be difficult. And we've made a number of changes in the people that are running the assets, brought more aggressive people, and if need be, we'll make more changes.

Just the final one on this point, Steve. I think for any larger company, there's really no great examples of being able to grow at a fast rate and generating good returns. Sometimes over a few years, luck happens and it can happen. But you've had a 5% to 8% growth objective, you've historically had top quartile returns on capital, is this really just an acknowledgment that having both of those goals is just not possible and you are picking returns right now?

Pretty much a lot of the growth is baked in for the next few years with the capital we've invested. But we need to do it with returns. It isn't just about volume growth. At some point in size, the need for capital becomes so -- a typical E&P today, whatever they say, I mean, they may sell assets to fund it, is spending, I don't know, 150% of its cash flow on capital. We obviously aren't spending anywhere near that nor would we. So you can't grow as quickly as they do. We spend more on capital as a percentage than are generated [ph]. So it's attempt to do both. I don't know where you come out in the percentages. Obviously, if we said, well, we're going to grow 15% a year, that wouldn't be something we could do. But we need to grow at a moderate rate, because I think the business -- if you don't grow at least some and on a regular basis, I don't mean by saying, well, in 2014 -- in 2017, we're on track for our 2017 program. We're going to grow in 2017, meanwhile we're going to deplete 5% a year. That's not what I call growth. But regular growth, you have a hard time attracting people, investors tend not to like it, they tend to compare you to basically depleting businesses. So you got to have a fair amount of growth. I don't know what the right percentage is. Right now, it's 5% to 8%. We're running really about 5%, currently. And there'll be a boost in 2015 from the Al Hosn project, which will bring the growth rate up. Over a long term, we're not going to just make the -- if you continue to drill high-decline wells, your capital will soar, because if your wells are declining 30%, 40%, you need huge amounts of cash to keep -- to replace the 40% and grow. And so we're shifting the program to more stable things so we can keep the capital under control. And that's really what we're doing underneath the hood, if you were to look at it that way. Instead of drilling as many high-decline wells, we're drilling more -- we're doing more stuff that has a lesser decline rate, which is what we historically did.

Your next question comes from Matthew Portillo of Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a few quick questions for me. You mentioned that on the release, the Q4 CapEx. And I was just curious if you could give us a specific number that you're looking at for Q4 CapEx?

Since my reliability on this has been crummy, the only thing I'll give you is that in September, we ran about 785, and we're coming -- on a month, that's a monthly number. And it's coming down from that as the wells come -- as it comes down. So that would give you sort of a feel for it. And I think that's a -- I've missed it so many quarters, I'd just as soon not miss it one more. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Sure. And then just on the M&A front, could you talk a little bit about the M&A market today and kind of your interest level? It sounds like -- kind of with the packages in the market today, there may not be that much interest, but just curious on your views.

We always look at stuff in our core areas. Really right now, the only area I would call core right now is the Permian. There's a rush to do -- by private people, to do something by the end of the year, lest their tax rates go up. There might be some things, but they would be oily and basically in the Permian, if there was anything. There's some other stuff going around, it's pretty gassy. And I'm not sure we would do that. The market is not good for sellers particularly. It may not be good for buyers either, but it's definitely not good for sellers. So especially for larger packages, I think you can do a $100 million deal and get 25 people to bid. At $500 million, you're lucky if you attract one. And I think that's really where the market is today, where there's money for small deals and really no money for large deals. The larger being $500 million deals. We don't have any appetite for large-scale M&A. We've said that for several quarters. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Perfect. And just a last question for me. Could we get just, I guess, a quick update on maybe where your rig count is roughly in the Permian, California and Mid-Con, Bakken? And then as we think about that 2013 program, can you give us just a rough direction on maybe where those are heading, either up or down, just directionally trying to get a better sense of that capital allocation?

I don't -- as far as next year goes, we sent the team back several times, as you could probably tell from the tone of my voice. So I'd hate to talk about what next year is going to look like at this point. We've cut back materially, I think in the -- Bill, in the Williston, how many rigs are you running?

We have 4 running right now, Steve.

And we peaked at?

We peaked at 14.

14, so that gives you a feel for the Williston. California, it varies a lot. We might drop -- and the type of rigs run. And so we're running about...

20 in California.

About 20, about 20 in California. Permian also, there's been some rigs dropped, and we peaked at?

Peaked at around 32.

And we're sort of 1/2 that.

We're at 21 now.

21. Okay. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And is that just a function of kind of where we are in the capital spend for this year? Or is that really, as we think about your program, and I know that you said you continue to go back to the drawing board. But just trying to get a sense of, is that activity going to accelerate a little bit into next year or you're pretty happy with the level?

I think the way I'm thinking about it at this point is, is that more or less, going into next year, it's going to look like this. My current plan would be to withhold a fair amount of capital from the units, that is drilling at these levels. Until I can see which units are doing well and which ones are not. And those that do well will get some more rigs to run, and those that don't, won't. And so I think going into the first quarter, you'll see sort of this level because that's the way we sort of manage it at this point. Beyond that, we'll just see.

Your next question comes from Faisel Khan of Citigroup.

I'm just trying to reconcile some of the comments you made on California. My understanding is the opportunity in California for you is supposed to have amongst the lowest breakeven sort of oil prices in those sort of projects, or those sort of wells that you're drilling, but CapEx is running about $2 billion a year. You seem to say, you're having higher declines in Elk Hills and costs in California are higher, and it seems like you're trying to rein in some of those costs. So what is it that's -- if this is such a great opportunity, what is the -- is it now what you thought it was 2 years ago when you first started out on the program?

The operating costs have doubled.

Okay. So is the resource opportunity not the same also?

No. The resource opportunity's the same. It's the cost to extract it. And if you thought that was fundamental, that's one thing. And then you say, well, okay. But it's not, I think it's fixable.

Does that mean the F&D cost that you kind of talked about maybe a couple years ago, of $5 a barrel, $10 a barrel, are more like closer to $20 right now in the current environment?

They're below $20. But they've come up with the well costs. And so they need to bring those down closer to where we were, and they need to bring their operating costs down. And the only way to do that is not to give more money to drill wells, even though the wells are economic, more than economic. Gas prices here are a little higher than the rest of the country and oil prices are higher. To throw more money at it is simply the wrong solution.

Sure, I understand that. And the rig count in California is 20 rigs now? Weren't you at 35 kind of a little bit earlier in the year? So it sounds like you've done like an about-face on that program.

It was around 30.

Around 30.

Okay. So within a short period of time, you've cut 10 rigs out of the operation?

Because we didn't like the cost of the wells.

Okay. And once again, the type of wells that you're drilling, this is all kind of the same depth, homogeneous sort of opportunities? Or is it kind of different opportunities spread across?

It's different opportunities. And again, as I said earlier, we shifted the program to lower decline wells.

Okay. So I mean, the shale program that you guys had outlined before has kind of been pulled back?

Some, not a lot.

And the exploration program that you guys were running in California?

The exploration program has been slowed by the permitting process. We're well behind on the exploration program, by the way. So we're 2 years behind where we thought we'd be.

And then if I were to look at your returns on capital employed, you're talking about a 13% sort of number for 2012. How would that split between international and domestic?

I don't know. International generates higher returns on capital employed. And that's really -- that's how the company is structured. I said it from the beginning, the high returns on invested capital come out of the international business the highest. And in domestic business -- because the leases are forever and then the oil in the international business are basically cut off by the life of the contract, so the upside, if you will, in the reservoirs over time and the long-term product price goes largely to the country, but you generate good returns meanwhile. Domestically, you get to keep all that. So you generate more money domestically, but the returns are less. And that's the balance in the company, and that's how you generate the above-average returns compared to an E&P which are well into the mid-single digits.

Okay, fair enough. And then the last question for me, so going into next year, given this focus on returns and given where the rig count is, do you still think you can grow production year-over-year?

Yes.

Your final question comes from John Herrlin of Societe Generale.

Just a few quick ones. You've been complaining about returns now for several quarters. Why weren't you more proactive with the organization, or why do you, it just takes them that long to react?

I don't know. I don't know why I wasn't -- it wasn't that I didn't try, it just didn't -- apparently it didn't translate.

Okay, that's fine.

And I've made some changes in the management structure.

Yes. Regarding the Permian, you had about a 36% working interest. Given the potential there, why not higher, because it seems like it's probably kind of your historic level?

Sorry?

With the Permian acreage, your working interest was about 36%.

Oh, I see. The gross and net using the play acreage.

Yes, correct. Why not higher, because it seems like it's probably more your historic level?

Yes. It would be nice if it were higher. We acquired some properties in the last couple of years in the areas that we historically hadn't been active, and those tended to be smaller interest. So you wound up with a lower average working interest in the new plays, and that's really -- it's just a result. We would like to have higher interest. In the end, when you drill a well, you might wind up with a higher interest, by the way.

Sure. Last one for me is on the Bakken. You've also kind of complained about those operations as well. Is that really critical to you going forward long term?

I think in the remarks, I pointed out the large amount of resource base there. I believe that the product prices on a relative basis have improved recently. One of the issues is at least partially on its way to resolution. The other issue is, that the wells cost too much, and we need large-scale reductions in the cost. If we can get the large-scale reductions then the assets clearly -- an asset we could -- that will be fine. If you can't achieve the large-scale reductions in costs that are required, then it's something for study.

And with that, I will hand the floor back over to Christopher Stavros for closing remarks.

Thanks everyone for dialing in this afternoon. And I expect you'll be calling us here in New York. Thanks.

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