Chevron Corporation (CVX) Q1 2011 Earnings Report, Transcript and Summary

Good morning. My name is Sean, and I will be your conference facilitator today. Welcome to Chevron's First Quarter 2011 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I will now turn the conference over to Vice President and Chief Financial Officer from Chevron Corporation, Ms. Pat Yarrington. Please go ahead.

Thank you, Sean. Welcome to Chevron's First Quarter 2011 Earnings Conference Call And Webcast. On the call with me today are Gary Luquette, President of our North American Exploration and Production Company. I've asked Gary to join me on the call this morning to give you an update on our recent Atlas acquisition and Gulf of Mexico activity. Chevron, and Gary specifically, have taken a leadership role in addressing the administration's concerns regarding drilling in the Gulf of Mexico. Gary serves as chair of the governing body leading the joint industry task forces that have been working to improve prevention, intervention and spill response capabilities with the goal of getting the industry back to work. Also on the call is Jeanette Ourada, General Manager of Investor Relations. Our focus today is on Chevron's financial and operating results for the first quarter of 2011, we'll refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. We ask that you review the cautionary statement shown here on Slide 2. Slide 3 provides an overview of our financial performance. The company's first quarter earnings were $6.2 billion or $3.09 per diluted share. Comparing the first quarter 2011 to the same quarter a year earlier, our earnings were up 36%. Upstream benefited from higher crude prices, and Downstream benefited from improved margins. Return on capital employed for the trailing 12 months was over 18%. Our debt ratio at the end of March was 9.5%. In the first quarter, we repurchased $750 million of our shares. In the second quarter, we are increasing our repurchase rate to $1 billion. Finally, we announced Wednesday that Chevron's Board of Directors approved a $0.06 per share or 8.3% increase in the common stock quarterly dividend. This is our 24th consecutive year of higher dividend payout. Now on Slide 4, cash generated from operations was nearly $10 billion during the first quarter. This is a record for the company. Our cash from operations provided excellent support for our capital program, the Atlas acquisition including associated debt retirement, our dividend payments and our share buyback program. At quarter end, our cash balances totaled nearly $17 billion. This put us in a net cash position of $5.3 billion. We see the 8% dividend increase and a simultaneous boost in our share repurchase rate as meaningful moves. Combined, we believe they send strong signals about our ability to both generate and to deliver tangible cash distribution rewards to our shareholders. Jeanette will now take us through the quarterly comparisons. Jeanette?

Thanks, Pat. Turning to Slide 5. I'll compare results of the first quarter 2011 with the fourth quarter 2010. As a reminder, our earnings release compares first quarter 2011 with the same quarter a year ago. First quarter earnings were $960 million higher than the fourth quarter. Starting on the left side of the chart, Upstream earnings were up $1.1 billion driven by higher crude oil realizations. Downstream results were lower by $120 million. Stronger refining and chemical margins were more than offset by unfavorable timing impacts in this quarter and the absence of fourth quarter gains on asset sales. The variance in the other bar reflects the unfavorable swing in corporate tax items. On Slide 6, our U.S. Upstream earnings for the first quarter were $519 million higher than the fourth quarter's results. Higher crude oil and natural gas realizations benefited earnings by $390 million. U.S. crude realizations were up 17% between consecutive quarters, higher than the 11% increase in the average spot price of West Texas intermediate. Our U.S. crude realizations are primarily tied to Mars, Louisiana light sweet and San Joaquin Valley heavy crudes, which all traded at premiums to WTI during the first quarter. Natural gas realizations improved by 11%, in line with Henry Hub spot prices. Lower sales volumes decreased earnings by $40 million between periods due to two fewer days in the first quarter compared to the fourth quarter. Lower operating expenses benefited earnings by $40 million between periods, primarily due to lower costs related to timing of maintenance activities. The other bar is comprised of a number of unrelated items, including the absence of unfavorable year-end LIFO inventory drawdowns and lower exploration and abandonment expenses. Turning to Slide 7. International Upstream earnings were up $611 million compared with the fourth quarter. Higher oil and natural gas realizations benefited earnings by $910 million. Average liquids realizations increased 20%, in line with the increase in average Brent spot prices. Natural gas realizations rose 5% between quarters. Lower liftings, primarily in Angola, Australia and Kazakhstan, decreased earnings by $255 million. This is directionally aligned with two fewer days in the quarter. Lower exploration expense benefited earnings by $140 million due to lower well write-offs and lower data acquisition costs. Moving to the next bar. An unfavorable change in foreign currency effects impacted earnings by $65 million. The first quarter had a loss of about $115 million compared to a loss of about $50 million in the fourth quarter. These foreign exchange effects have no direct impact on cash. They are primarily balance sheet translation effects. The other bar reflects a number of unrelated items, including higher withholding taxes on affiliate dividend distributions, partly offset by a lower depreciation expense. Turning to Slide 8. During our March Security Analyst Meeting, we discussed our plan to move certain major capital projects that have reached peak production into our base business. The map shows the specific projects being recategorized. The two bars on the graph show fourth quarter production with both the original split between base business and MCPs and the new categorization. The impact was a shift of 482,000 barrels of oil equivalent per day. Slide 9 summarizes the quarterly change in Chevron's worldwide net oil equivalent production. Production decreased 26,000 barrels per day in the first quarter compared with the fourth quarter of 2010. Higher prices reduced volumes under production sharing and variable royalty contracts during the first quarter, decreasing production about 22,000 barrels per day. In the past, we have used the change in WTI to calculate a PSC price effect. Given the recent divergence in the WTI-Brent Spread, going forward, we will use the change in Brent to calculate the price effect because it is more closely tied to our international realizations. The average Brent price increased $19 per barrel between quarters, which resulted in about a 1,200 barrel per day volume reduction for each dollar increase in Brent. Recall that over a range of prices, PSC effects are not linear. As prices rise, the PSC production impact decreases. Weather conditions in onshore U.S., Australia and the U.K. lowered production 15,000 barrels per day between quarters. Base business production increased 7,000 barrels per day, largely driven by an increase in cost recovery barrels in various locations, offset by normal field decline. This bar also includes a small positive impact from the addition of 6 weeks of Atlas production. Contributions for major capital projects increased first quarter production by 4,000 barrels per day, primarily driven by continued ramp up at Perdido and Frade. We reaffirm our full year production outlook of 2.79 million barrels per day. The outlook assumes $79 per barrel, the same average price as 2010 and does not assume OPEC curtailments, material security or market impacts. We'll provide another update on the second quarter earnings call. Turning to Slide 10. U.S. Downstream earnings fell $33 million in the first quarter. Indicator margins improved earnings by $170 million, driven by higher refining margins for both the Gulf Coast and West Coast. Both areas had stronger demand especially for distillates. This stronger demand occurred simultaneously with normal planned refinery maintenance. Stocks were depleted and margins widened as a consequence of these two divergent forces. The next bar shows a $380 million negative earnings variance, primarily reflecting the absence of a fourth quarter gain on the sale of our interest in the Colonial Pipeline Co. Chemical earnings improved by $90 million mainly due to higher margins for olefins and aromatics. The other bar includes positive impacts from lower turnaround activity in the first quarter and a favorable pipeline rate settlement. On Slide 11, international Downstream earnings were also lower, falling $87 million from fourth quarter's results. Margins reduced earnings by $25 million. Stronger refining margins in Asia and Canada were more than offset by supply mix effects in Asia and lower European refining margins. Timing effects represented a $230 million negative earnings variance between quarters, reflecting a swing from a positive $35 million in the fourth quarter to a negative $195 million in the first quarter. The primary drivers were unfavorable inventory effects, mostly in Asia during the period of rapidly rising prices and the absence of fourth quarter's favorable year-end LIFO effects. Lower operating expenses across multiple categories benefited earnings by $35 million. The other bar includes a number of unrelated items, including small asset sales, improved shipping results and a favorable tax variance partly offset by lower volumes. Slide 12 covers all other. First quarter net charges were $388 million compared to a net $294 million charge in the fourth quarter. The $94 million increase between quarters is primarily due to unfavorable variance in corporate tax items. We believe our quarterly guidance range of $250 million to $350 million for net charges in the All Other segment is still appropriate going forward. Now I'd like to turn it over to Gary for an update on North America.

Thanks, Jeanette, and good morning. It's good to be here with you. I'd like to give you a brief overview of my area of responsibility, Chevron's North America Upstream operations, and then discuss recent progress in the Gulf of Mexico and the Atlas acquisition. Turning to Slide 14. North America has a tremendous natural resource base and they are close to fully developed infrastructure serving large markets, making it an attractive place to do business. We operate a solid mix of base business assets and major capital projects. Our portfolio includes both conventional oil and natural gas and unconventional energy sources such as oil sands, coalbed methane and shale gas, and we continue to grow our portfolio. Our U.S. operations are anchored by assets in the Gulf of Mexico, California, Texas and the Rocky Mountains. In Canada, our activities reached throughout Atlantic Canada, the Arctic and the Western oil sands. In total, our North American operations account for about 1/4 of Chevron's production. During the rest of our time together this morning, I want to focus on the Gulf of Mexico and our recent Atlas acquisition. Let's start with the Gulf of Mexico. Slide 15. With more than 60 years of experience operating in the Gulf, we've proven that we can explore for and produce oil and gas both safely and in an environmentally sound manner. We produced 9 billion barrels of oil equivalent as we have progressed development from the shelf into the Deepwater. We maintain a significant presence throughout the Gulf of Mexico. We are a leading leaseholder across both the shelf and the Deepwater. In 2010, we averaged 260,000 barrels a day of oil equivalent, making us one of the largest producers in the region. On Slide 16. Our Gulf of Mexico portfolio has a wide variety of assets and projects. These include offshore platforms in shallow and deep water, onshore operations, gas plants, water floods and subsea wells. We drill in deep and shallow water and operate in high-pressure, high-temperature environments. We have added acreage through recent lease sales, which allow us to pursue promising ultra-deep gas opportunities in the shallow waters of the shelf. Despite the challenging regulatory environment, Chevron remains very bullish on the Gulf of Mexico. Let me tell you about some recent developments. Turning to Slide 17. In 2010, our plans were to drill 4 exploration impact wells: Moccasin, Coronado, Oceanographer and the Buckskin appraisal. These wells were delayed by the drilling moratorium. We are ready to get back to work, and these wells are our top priority. We will be able to do so once the new permit requirements are fully understood and permit applications are revised and submitted. We'll also need for the regulators to establish an efficient method for reviewing and approving what is expected to be a backlog of permit applications. In late March, we received the permit for our Moccasin exploration prospect. This was the first such exploration permit granted to any operator after the moratorium was lifted. The rig arrived on site two days after receipt of the permit, and we'll soon be drilling. The Buckskin permit application was submitted on April 18. We're expecting an approval in the next week or two. We have also received a permit for our second water injection well at the Tahiti 2 project, and drilling is underway. Chevron currently has 3 deepwater drillships in the Gulf. Two have returned to work and the third is awaiting a permit for our Buckskin appraisal well. The good news is that we see activity slowly beginning to ramp up, but it's still too early to know what the new normal for pace of permitting and overall activity levels will be. We're hopeful the administration shares our goal of expedited permitting now that we've established higher performance standards, so we can move forward in developing our domestic energy supplies. Our near-term deepwater drilling program will require the approval of approximately 10 development and exploration plans, and approximately 15 drilling permit applications for both development and exploration wells. These are in various stages of preparation for submittal. We plan to begin drilling development wells at Jack/St. Malo in the second half of this year. This was always the plan. And to date, start-up remains on track. Should permitting delays persist further into the year, the number of wells available at start up could be impacted, but we remain committed to previously communicated first oil dates. I'd now like to provide an update on Atlas. Turning to Slide 18. We're very pleased with the Atlas acquisition, which closed in mid-February. These assets are in one of the sweet spots in the Marcellus Shale, one of the key shale gas plays in North America. With the drilling carry provided by our Marcellus joint venture partner, Chevron's near-term investment is limited. Over the next several years, the joint venture partner will fund 75% of our drilling costs, up to a total of $1.4 billion. Equally important, the acquisition has provided us with a highly skilled workforce with strong operating experience and established land management capabilities. They are strong organizational synergies with Chevron's existing technical expertise and our global experience with large-scale developments. We have created a new business unit to manage our acquired assets. We are making good progress on integration and expect transition activities will continue throughout the year. Early activities are focused on capturing operational synergies on capital project management and execution and smoothly integrating our financial and IT systems. We have a very active year planned. There are currently 9 rigs operating in the Marcellus, and we expect to drill a total of 70 wells this year. We expect 2011 production for both the Marcellus and Antrim shales to average about 115 million cubic feet of gas per day. Our pace is measured. We are optimizing our development well programs to lower our costs, improve well performance and shrink the time from well completion to hook up and production. This is a long-term play for us. We're in a great position as we ramp up for a multiyear drilling program. It's a great marriage between Atlas' commitment to the resource and Chevron's strong subsurface expertise and capital project discipline. Admittedly, it's very early, but all signs are positive. And we expect to capture the value we identified in our initial evaluation. Finally, the state of Pennsylvania has asked all Marcellus operators to cease delivering produced water associated with shale gas extraction to publicly owned water treatment facilities by May 19. It was always Atlas' and Chevron's plans to discontinue disposal of surplus-produced water into these facilities by the end of the year 2011. With this recent request, we will accelerate our plan and comply with the May 19 date. With that, I'll now turn it back over to Pat.

Thanks, Gary. We're now on Slide 19. I'd like to wrap up with a few comments on Chevron's strategic progress during the first quarter of the year. We've stayed the course with strong safety performance after achieving our safest year ever in 2010. In the Downstream, we continued to progress our portfolio rationalization efforts announcing the sale of the Pembroke Refinery and associated marketing assets in the U.K. and Ireland. We completed the sale of our Downstream businesses in the eastern Caribbean and in certain countries in Africa. We have also announced an agreement to sell our Downstream businesses in Spain. Additionally in Downstream, we reached a final investment decision on the construction of a $1.4 billion lubricants manufacturing facility that will be located at our Pascagoula, Mississippi refinery. This project leverages a strong refinery and proprietary Chevron technology to meet the growing demand for higher-margin premium lubricant. We had a number of accomplishments in the Upstream. As Gary discussed we completed the Atlas transaction. We were awarded 1.5 million acres in Romania, further bolstering our global shale gas portfolio. We continued our exploration success in Western Australia with the Orthrus-2 natural gas discovery, and we announced 2 new oil discoveries in the Moho-Bilondo area offshore Republic of Congo. In addition, we signed a Sales and Purchase Agreement with Kyushu Electric for the delivery of LNG from the Gorgon Project. I'll close by mentioning that our Upstream operations are just under $25 per barrel for the quarter. Based on preliminary competitor results announced to date, we outpaced our nearest competitor by nearly $5. We've led our peer group on this metric now for 7 consecutive quarters. We're definitely off to a great start in the first quarter of the year, both financially and operationally. Now that concludes our prepared remarks. We welcome your questions at this point. So, Sean, please open the lines.

[Operator Instructions] Our first question comes from Doug Terreson with ISI Group.

In International Downstream and specifically the unfavorable variances in that area, I want to see if you will elaborate a little bit further on the supply mix effect, and I think Jeanette attributed to Asia in the period. That is, what were they, what products do they involve, et cetera. Just some color, if you could.

Well, Doug, it's really across multiple different products. And what really happened is there was very rapidly increasing prices in the quarter so at the end of the quarter as we revalued our inventories, you see the big negative effect there. Of that bar, $170 million is related to inventories, so that is the key driver of that bar.

Okay, and also in E&P, and specifically, on global natural gas, there seems to be progress on block A in Cambodia and even more on block B in Vietnam. So I want to see, if we could get an update on those projects, and also on Venezuelan gas, that is, if there's anything to update on Venezuelan gas.

Let me start with Vietnam. So Vietnam, we commenced front-end engineering and design in the first quarter of 2010, and we do expect FID decision later this year. So that project is moving forward. Cambodia, we're still assessing the Cambodia opportunity, and we haven't laid out any near-term milestones for Cambodia. I'm sorry, your last question?

Yes. Venezualan gas, is there anything new to report there?

No.

Our next question comes from Paul Cheng with Barclays Capital.

Gary, two questions, one in Atlas. What's the growth rate you guys are targeting or expecting for the next two to three years, given you have your partner carry your cost? And then, what kind of expected return that you have in mind on that? The second question is that you do you have some reasonable land position in the Permian Basin? Is there any -- what type of opportunity you have in terms of the nonconventional shale oil in your land position? Also that, you guys have some of your competitors start to be more aggressive trying to get into early into the new shale oil play either both in Canada or as well as in the U.S. but does not seems like that, Chevron is not more -- is as aggressive or would that maybe, making as much noise as some of your competitors. Wondering there if there's any insight that you can share here.

Okay. Thanks for the questions Paul, there's a lot there. So let me see if I can unpack these one at a time starting with Atlas. It's way too early for us to forecast growth rates. We are just a couple of months now into taking ownership of those assets. As I mentioned in my remarks, our focus early on is going to be in trying to build a very efficient execution process that's going to allow us to start earning acreage, and so we'll have to let that unfold a little bit longer before we can start pinpointing the specific growth objectives for you. With respect to the Permian Basin, we are in a great position there. In fact, just a few weeks ago, we celebrated our 5 billionth barrel production milestone from the Permian basin with Chevron and Chevron legacy companies operating out there, and we have a tremendous amount of opportunities left. So we're investing quite aggressively, not just in the conventional sorts of plays, but also, we're looking at some tight oil. Now this would not be considered shale oil, but certainly ultra-tight oil that we feel will represent a nice opportunity for us to continue to add volume in the Permian Basin. And I think your third question dealt with kind of our views towards Canada and some of the unconventionals. Yes, and I think...

Not just Canada, but also U.S. also, Gary.

Okay, well, that's good that you made that clarification, because I think Paul, we typically look across North America with the same sort of scrutiny. We look through the same lenses, and we are watching what is unfolding. We're evaluating opportunities as they come along. Many of these opportunities that present themselves are quite pricey because there were independents that got involved very early on in some of the land acquisition. So we're going to continue to look and evaluate opportunities. But there's nothing in particular that I can report on.

Gary, are you guys looking at more on the already identified existing play? Or that trying to look and venture into some untested play, which the entry costs are much lower?

Well, it's a combination, Paul. So as we do our regional analysis to try to understand the geology and the producing mechanisms, we're looking across the board. Some of those lead us very early into possible entry positions, early entry positions and others. People have already acquired the land and we're continuing to look at ways that Chevron can create value in those plays.

Just a final one, a short one. Pat or Jeanette, can you tell us at the end of the first quarter from an inventory standpoint, are you still under lift over lift or neutral?

We're slightly under lifted, not too dissimilar from fourth quarter.

Can you remind us then, how much?

About 1%, Paul.

1%?

About 1%.

Our next question comes from Edward Westlake with Credit Suisse.

A question just following on to Gary from the previous question on the Permian. You've talked about some exciting opportunities in the nonconventional and the conventional. Can you just talk about what sort of the general -- will those opportunities be able to offset decline? Will you be able to grow the Permian or maintain it? And the same question with regards to your Californian oil position.

As you are aware, those two positions, the Permian and our heavy oil holdings in California are very, very mature assets. Many of these fields, certainly in California, are 100 years old, and in Permian we're talking about north of 50 years old. So I would certainly look at it as a win for Chevron, if we could hold our production levels that we currently have or at least arrest some of the decline that you see in the normal field decline. So I think our objective would be to try to replace declining production with some of these new opportunities and try to hold what we have, which are quite sizable. We're nearly 200,000 barrels a day in California and over 70,000 barrels a day in the Permian Basin, and we want to try to hold that if possible.

And then a follow-on question on the Gulf, the ultra-deep gas in the shallow waters. When do you think you will test that?

Well, actually that play is being tested now. Paul (sic) [Ed], there are some smaller players that -- sized companies that have been involved in this for some time and have pretty much proven that the gas is there. And we made a move here a year ago and acquired some additional acreage, and this is on top of acreage that we already hold by production, by producing through some of the shallower zones. So we actually are participating in an exploration well at present with a third party. And we hope to get another exploration well in, in the 2011 campaign.

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

I am going to try a couple also. Pat, if I could try a couple for you, and then one for Gary to take advantage of him being here. The quick ones from me. You've redefined the base, I guess, as you explained in your prepared remarks. What does that do to actually change the underlying decline rate? Is there any change there in your guidance? And if I may just bolt on my other one, the exploration charges were quite light in the quarter. Is that just a seasonal issue because it was light Q1 last year also? Or did that reflect less dry hole charges or load overall expenditures? And then I've got a follow-up for Gary, please.

Okay. Doug, thanks. With regard to your first question on the decline rate, we're basically in the 3% to 4% range. There's no change in the guidance that we have given out previously. We just wanted to be very clear about the change in the base. We mentioned it in the March meeting, we just wanted to be very clear this time through. And with regard to the second question?

Yes, so on exploration, it was lower for both reasons that you mentioned, Doug. There were lower well write-offs in the first quarter, and also lower data acquisition costs.

Okay. But no real change in the overall trend?

No. I mean, it can be very lumpy as you know, just given the timing of well write-offs. That really is normally is the rationale behind any quarter-to-quarter variance.

Okay, thank you. Gary, I appreciate you being on the call this morning. It's really more of a big-picture question. There's been a lot of talk about changes to drilling subsidies and so-called tax benefits for the industry. I just wondered if you could give us your take on the current debate, what Chevron's potential exposure would be. I'm guessing that's not significant. Just the overall perspective that Chevron brings to this. And if you are, in fact, having any discussions with the government over how their consultations with industry. That would be great.

To my knowledge, we're not having any specific discussions with the government right now with respect to specifics, sorts of incentives that have been in place. We've taken a general position that certainly when you look at the Deepwater Gulf of Mexico, Deepwater royalty relief was a huge success for the government, for industry and for the American people. It accomplished what it set out to do, which was to stimulate marginal play, get activity in there, get proof-of-concept going, get investment going, and eventually, get production that drives a tax and royalty revenue to the government. So it's been a huge success. So we've tried to take that message and try to communicate that to everyone that'll listen in the administration that incentives do work. And when it can spur investment, then good things can happen in follow on. But that's just kind of a general position. I don't know if that satisfies what you were looking for whether you'd like something else.

Well, I'm just curious, so I'm not expecting any numbers. But just an order of materiality, if drilling subsidies and tangible drilling costs and so on were revoked, if you like, you don't, I imagine, have a significant onshore position that would meaningfully impact you. I'm just looking for some confirmation if that it would be material or if it'd be less material, would it change your investment strategy? Would it alter your investment in the base decline onshore U.S. Those kind of issues are really what I'm trying to get to.

Right, and I think, Doug, we actually take issue with even using the word subsidy in some of the dialogue that the administration has had, because this really is just deductions that have been allowed for our industry, as well as a whole host of other industry. So it really is not a subsidy at all here. So our dialogue back with the administration really is trying to get clarity around those points. And really when you think about it, particularly, around the IDCs [intangible drilling costs], this is something that's been in play for a long period of time, for a decade. It allows you to have an earlier deduction for a risky business that, for a smaller player in particular, allows them to afford the huge capital outlays that they're putting at risk. And so I think, for smaller companies in particular, this is an enormous issue for companies like that. And really the message we want to get across here on this point is that in order to make more supplies available for the globe and to get energy prices into the more affordable range, what you really want to do is incent production, incent the domestic supplies, not tax them or take away tax deductions that they have currently.

I'm sorry Pat, would it change your investment policy or not?

Well, I think it's a hypothetical. We don't really want to go there. I mean, obviously, we'd have to look at the full economics of what's allowed from a tax code standpoint.

I understand.

Our next question comes from Mark Gilman with The Benchmark Company.

Had a couple for Gary. First, Gary, markets in Coronado, are those Miocene or lower tertiary prospects?

Lower tertiary.

In both cases?

Yes.

Okay. Can you update us or comment at all on your planned activity in the Duvernay?

We're going to start an exploration appraisal program late this fall, Mark. And we have additional wells planned in 2012. We're going to do some seismic work and use the seismic and well work to start trying to better understand the resource potential in that recent lease acquisition.

Okay. And just one more, if I could, regarding Atlas specifically. How does the activity level envisioned for this year compare to that which Atlas had underway previously? And can you give me a rough idea what some of the individual well metrics look like in terms of IPs or EURs, Gary?

Okay. Mark, first of all, pretty substantial increase year-on-year in terms of activity levels. But I must say not as high as what Atlas had planned as we have taken control of that operation and started working with the Atlas employee base and the contractor base, I think we felt going a little bit slower early on to try to take a more measured approach towards building the execution efficiency that we want was in order. But we're going to be on the level of about 70 wells this year, which is about 5x what they drilled in 2010. So we're on a very steep curve. It's very early in the processing of that resource base, so we expect to continue to increase our activity levels there but at a very measured pace to make sure that we get it done right, the Chevron way. And on the last question, I think it's just too early for us to start putting a dot on the map with respect to IPs or EURs. It's -- obviously, we have expectations for that resource, but it's still too early for us to really be able to represent that.

Our next question comes from Faisel Khan with Citigroup.

I was wondering if you could help us with the overall picture on North America, Gary. If we're looking at the returns on capital with the onshore unconventional liquids play, and if we're looking kind of deep offshore, I guess what's -- where is the -- where are the relative returns? What's the better place to put that incremental dollar to work, if you had to be forced to put a dollar at one place or another?

Well, we have a very diverse portfolio, Faisal, and we're in the business both for short-term returns as well as longer term, positioning ourselves to have good access to resources for the next 10 years and the 10 years after that. So we kind of use a basket, if you will, of performance metrics that we use in allocating our capital programs. So for the -- to pick winners and losers, some represent a lower return, longer life sort of resources. The others represent shorter payout, higher return sorts of opportunities. And what we try to do is balance that across a portfolio of investment opportunities.

Okay. So no, but you can't -- I mean, you can give me kind of relative view which areas are better than others in terms of the different prospects?

No, I really can't because we're managing across the North American portfolio, and then, the North American portfolio is then fit into a global Upstream portfolio. So I think it would be just too hard to do that right now.

Okay, got you. And if I'm looking at the 15 permit applications that you guys intend to file, are those going to all come at once or are they going to come kind of over a period of the next 12 to 24 months?

So they're going to come over a period of time. But the permit applications that I laid out in my opening remarks are going to come sooner versus later. These are all permits for exploration wells, development wells, delineation wells associated with the program that we have laid out over the next couple of years. So we expect to move those permits as swiftly as we can through our shop and into the government shops so that they can start their process of review and approval.

Okay, great. And then, if I'm looking at the Lower 48 for you guys for your onshore rig activity, both gas and liquids, how many rigs do you guys have deployed between those 2 plays, and how do you think that'll trend throughout the year?

Well, I can't answer how many rigs. It's just a detail that I don't have with me this morning, but I can assure you that rig count is higher in 2011 than it was in 2010. We are increasing activity, both onshore and offshore, and so those counts are increasing.

Okay. Great. I appreciate the time.

Our next question comes from Iain Reed with Jefferies.

I've got a question for Gary and then one for Pat. Gary, on the -- you've been obviously responsible for talking to the regulatory authorities about the Gulf of Mexico drilling. In terms of the increased oversight and the requirements for testing or BOPs, et cetera, how much do you think that's going to add to cost on a kind of average exploration and an average development well in your opinion?

Well, we still haven't, I think, got at a run rate and a pace, Iain, that would let me understand what the total revamp system incremental cost might be. I think the cost that we are -- the change that we most are concerned about is the time required to process permits. Clearly, there's going to be incremental costs. We know, for instance, on the recent well designs that we have put in we've had to enhance our casing program. In some cases, running casing all the way back up to the surface, whereas in the past, that was done in a tie-back fashion. So we're seeing incremental costs on the casing program with those wells that could be in the range of 10% of the well cost. But the whole system of inspection, certification, implementing, verifying, certifying, all that is yet to be sussed out. We're going to need more time.

So have you actually reconsidered drilling certain wells due to this increased requirements that you see now?

No, it hasn't changed our view towards individual wells are towards the Gulf of Mexico in a broader sense.

Okay. Thanks. And one question about Australia. You've had further exploration success in the Carnarvon, and you showed us up the -- on the Strategy Meeting your resource base there. I just wonder how close you are now to starting serious work on the fifth train at Gorgon now.

Well, I think it's really premature to have us go down that path. I mean, we did show you materials back in March that suggested we've got additional gas supplies available that would support or underpin a fourth train. But I don't want to get too far out over our skis and thinking beyond that. I will say it is a hugely prolific basin. However, and so if that becomes -- if we have continued exploration success there, then that's something that would certainly would be in our sights. Obviously, brownfield expansions are much more economic than greenfield. And if there is a way to see ourselves to a fifth train, we certainly would like to do that, but we're not at that stage of committing to that at this point.

Do you think you need more drilling to do that or is it just more interpretation of what you've got?

I think there's more drilling and interpretation.

Okay. And one final question, on your dividend increase, I was a bit confused about whether that applied to this quarter or whether that's a second quarter event.

It'll be a second quarter payment.

I mean, yes. Undeclared, it has...

Yes. So second quarter dividend for the second quarter payment will be at $0.78 a share.

Okay. So the first quarter dividend is still $0.72?

That's correct.

Our next question comes from Allen Good with Morningstar.

I wonder if, Gary, if you could just explain a little bit on the new business unit that was established with Atlas. Is that going to include all of Chevron's pre-existing unconventional resources, and will that wrap in the global portfolio as well?

Thanks for the question Allen, and the short answer is no, it will not. Initially, the new business unit is going to be focused on the recent acquisitions. The assets that Atlas had in the portfolio that includes the Marcellus as well as the Antrim production out of Michigan. We want this unit to get focused early on, on those assets to make sure that we have a smooth transition, a smooth integration and we get started on the right foot. We also realize that there is going to be things that we're going to develop and learn from this asset base that's going to be very applicable to some of the shale gas acquisitions, the acreage that we picked up over the course of 2010. So we're going to start working on surrounding this organization with the center of expertise for shale gas that will allow us to leverage those learnings. But at the same time, we want to be very careful that our start in the Marcellus is a good one, a safe one, a reliable one, so that we can build a very sound base there for decades to come.

Sounds good. I wonder if you could elaborate as well on your water treatment plans? I know that whole situation got lot of press lately, any detrimental impact or supposed detrimental impact from the frac-ing fluid and the other water treatment plants. Just interested in what your plan is there, if you're not going to be able to treat it at the public utilities anymore.

Right. Well, eventually we were going to get there any way, Allen, and we were going to do that through adding a second and eventually growing our frac spreads, so that we could drill and complete more wells, that's on the natural plan. And what we're going to do is we're going to accelerate some of that activity, so we'll actually add a frac spread to our operational a little earlier. That will consume much of the surplus water and then the rest of the water that is left over we'll inject in permitted disposal wells.

Okay, sounds good. I appreciate it.

Our next question comes from Pavel Molchanov with Raymond James.

Just hope to get an update on two of your frontier programs, the Liberian entrance from late last year, and also your plans for Romania from earlier this year.

Yes, really, we don't have a tremendous amount of update relative to what we said back in March. We have the three licenses that we acquired. We have a 70% interest there. Obviously, it's a significant deepwater -- there have been significant deepwater discoveries in the region, and we're maturing the prospects. We plan to drill a well later this year.

That's Liberia and on Romania?

On Romania, it really is drilling as well. I mean, further evaluation, seismic activity as the year progresses. There's not extensive, more update that I can provide at that point in time.

Our next question comes from Herman Ladeuix with CLSA. Hernan Ladeuix - Credit Agricole Securities (USA) Inc. I have a question about the energy projects in Australia. I wonder if you can share any thoughts about the impact of the Australian dollar on the cost of Gorgon and potentially on the plans for Wheatstone?

Right. I mean, both projects, Gorgon and Wheatstone, obviously, can be -- could be affected by the foreign exchange impact. But I'd just say both projects, and let me just focus in primarily on Gorgon. It's a global project. We have a lot of activity that's going on in Australia, but there is an awful lot of the procurement activity that is done globally. So we have currency impacts that are Korean, other Asian countries, European, U.S. dollar, et cetera. So it is a multicurrency project, and it's part of the impact that will occur over multiple years. Same thing would be true of a Wheatstone Project. I would just offer though that we have, as we go forward on these projects from an FID standpoint, we have an awful lot of the cost activity that is well-defined and well-scoped, and in many cases, fully committed. So on Gorgon, we committed, reaffirmed back in March that we were on schedule and on cost for the Gorgon Project. On Wheatstone, we intend to go to FID later this year. We have the contracts out for bid at this point in time, and we should have a firm estimate of what that project cost will be at that point in time. Hernan Ladeuix - Credit Agricole Securities (USA) Inc. But, Jeanette, should we still think about the $37 billion on that, I mean, given that the fact that not only the Australian but other currencies have moved cost substantially, at the same the FID?

Yes, you should still consider to think about the $37 billion. Remember, that's over a 60-month construction period, and the dollar moves up and down, and there's an awful lot of variation that can occur. So we're early days into these. We're only about 20 months or so into the Gorgon Project, so there's a lot of time left as well.

I'm not showing any further questions in the queue at this time.

All right. I guess that we'll close off here, and let me wrap up and just say, I thank everybody's time and attention here this morning and the participation on the call. I particularly want to ask -- applaud the folks who asked the questions because that helps get more clarification out there. Thank you, everybody. I appreciate your interest in Chevron. Goodbye.

Thank you, ladies and gentlemen. That concludes Chevron's First Quarter 2011 Earnings Conference Call. You may now disconnect.