ConocoPhillips (COP) Q1 2014 Earnings Call Corrected Transcript: 01-May-2014
Ellen R. DeSanctis - VP-Investor Relations & Communications, ConocoPhillips
Jeff W. Sheets - Executive Vice President-Finance & Chief Financial Officer, ConocoPhillips
Matthew J. Fox - Executive Vice President-Exploration & Production, ConocoPhillips
Paul Y. Cheng - Analyst, Barclays Capital, Inc.
James Sullivan - Analyst, Alembic Global Advisors LLC
Doug T. Terreson - Analyst, International Strategy & Investment Group LLC
Paul B. Sankey - Analyst, Wolfe Research, LLC
Ed G. Westlake - Analyst, Credit Suisse Securities (USA) LLC (Broker)
Blake M. Fernandez - Analyst, Howard Weil, Inc.
Doug Leggate - Analyst, Bank of America Merrill Lynch
Faisel H. Khan - Analyst, Citigroup Global Markets Inc. (Broker)
Roger D. Read - Analyst, Wells Fargo Securities LLC
Pavel S. Molchanov - Analyst, Raymond James & Associates, Inc.
Asit K. Sen - Analyst, Cowen & Co. LLC
MANAGEMENT DISCUSSION SECTION
Operator: Welcome to Q1 2014 ConocoPhillips Earnings Conference Call. My name is Christine, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.
I will now turn the call over to over to Ellen DeSanctis, Vice President-Investor Relations and Communications. You may begin.
Ellen R. DeSanctis, VP-Investor Relations & Communications
Thanks, Christine, and good morning to everybody. With me here today are Jeff Sheets, our EVP of Finance and our Chief Financial Officer; and Matt Fox, our EVP of Exploration and Production. Jeff will cover the quarter's financial highlights, and then Matt will take us through the quarter's operational highlights and provide some color on what to watch out for or what to pay attention to for the remainder of the year. Then we'll have Q&A, and we'll ask during Q&A, if you would, to limit your questions to two. Of course, jump back into the queue if necessary.
We will make some forward-looking statements this morning, and the risks and uncertainties in our of future performance are described on Page 2 of this morning's presentation materials, also in our periodic filings with the SEC. This information as well as our GAAP to non-GAAP reconciliations and additional supplemental information can be found on our website.
Now, I'll turn the call over to Jeff.
Jeff W. Sheets, Executive Vice President-Finance & Chief Financial Officer
Thank you, Ellen. Hello, everyone, and thank you for joining us today. As you know, we just recently held our 2014 analyst meeting in New York, where we reaffirmed our plans to deliver double-digit returns annually to our shareholders. We outlined our production and margin growth plans for the next few years and hopefully gave you increased confidence on our ability to deliver on those plans.
We have an exciting year ahead, and as we reported this morning, we're off to the strong start. So slide 4 lists our key highlights for the first quarter. Operationally, we had a very good quarter. We produced 1.53 million BOE per day from continuing operations, excluding Libya. Adjusted for dispositions and downtime, this is up about 3% compared to last year's first quarter. So we're seeing growth. We also made progress on key activities that will continue to drive organic growth. We delivered on key milestones around our major projects and continued our strong performance in the unconventionals.
Exploration and appraisal activities continued during the quarter in the North American unconventionals, the Gulf of Mexico Deepwater, Australia, and elsewhere. These activities are key to our reserve and production growth beyond 2017. Financially, this was also a very strong quarter. We achieved adjusted earnings of $2.3 billion or a $1.81 per diluted share. This was quite a bit higher than expectations, and I'll address some of the drivers of this stronger than expected performance on the next slide.
During the recent quarter, we generated $4.4 billion in cash from our operating activities alone. We also had positive working capital change of about $600 million and a distribution of $1.3 billion from FCCL, so total cash from operations was $6.3 billion. And our balance sheet remains very healthy with over $7.7 billion in cash and short-term investments on hand as of the end of the quarter.
Strategically, we delivered on both production and margin growth this quarter. We continue to expand our inventory of organic growth opportunities to support our growth goals. And importantly, we remain committed to delivering double-digit returns to our shareholders annually, including a compelling dividend. So all in all, the first quarter was very strong operationally, financially and strategically.
So now, I'm going to turn slide 5 for a discussion on earnings. First quarter adjusted earnings of $2.3 billion were up 29% compared to last year's first quarter and up 30% sequentially. Adjusted EPS of $1.81 was higher than consensus, about a dime of the difference or roughly $100 million was due to the North American natural gas price realizations that were stronger than the realizations indicated by changes in market prices. Another dime or about another $100 million was due to gains from marketing of third-party natural gas during the quarter.
As a reminder, we have a strong commercial gas marketing organization that markets both equity and third-party gas in North America. Given the high volatility in first quarter gas prices, our commercial team was able to capture some benefit by supplying both equity and third-party gas into premium markets. This benefit from our third-party activities and is not necessary repeatable but it speaks to our strong marketing capability.
First quarter segment earnings are shown in the lower right side of this chart. The financial details for each segment can be found in the supplemental data that accompanied this morning's release, but let me address a couple of items about the segments. Lower 48 earnings included the marketing gain I just talked about as well as strong realizations for natural gas.
Canada segment earnings were very strong, again reflecting stronger bitumen prices and gas realizations. Gas realizations for the quarter were $5.81, reflecting both strong ACO pricing and the placement of some volumes into premium markets during the quarter. Canada segment earnings also included approximately $60 million benefit from foreign exchange, which was offset mostly by foreign exchange losses across other parts of the portfolio. Alaska was pretty straightforward with nothing unusual to highlight in the quarter.
Europe operations performed well in the quarter with growth coming from several major projects, and if you look over the past several quarters, we're starting to see the benefit of volume growth in this segment. Our Asia Pacific and Middle East segment was impacted by lift timing differences in China and Western Australia, but otherwise was in line with expectations. And finally, our corporate segment was in line with the previous guidance.
So if you'll turn to slide 6, I'll cover our production results for the quarter. As you know, our convention for production is continuing operations less Libya. On this basis, our first quarter averaged 1.53 million BOE per day. Normalized for disposition, this compared to 1.495 million BOE per day in the first quarter of 2013. The waterfall shows that over the period, we had 6,000 BOE per day more of planned and unplanned downtime than in the first quarter of 2013 and net growth of 41,000 BOE per day. That represents a 3% increase compared to a year ago. The box on this page illustrates the composition of this 41,000 BOE per day of growth. And as we discussed at our recent analyst meeting, we are growing in the highest margin portions of our portfolio, and this growth of higher margin production is driving growth in the company's cash margins. And we'll discuss that margin growth on the next slide, which is slide 7.
This slide shows changes in our cash margins from the first quarter 2013 to the first quarter of 2014 and also on a sequential basis. On the left side of the chart are the margins on an as-reported basis which were up over 20% year-over-year on strong natural gas prices and on the right are the margins on a price-normalized basis. So on a price-normalized basis, margins increased 13% year-over-year. Of this improvement, over a third or 5% is due to our underlying liquids growth, especially in areas with more favorable fiscals. The remaining 8% margin improvement was due to the benefits related to equity and third-party gas marketing activities that we've just discussed as well as Libya being down. So we are delivering on our commitment to improve margins as we grow, not just generating growth for growth's sake.
I'll conclude my prepared remarks with our cash flow waterfall, which is another good story. So, I'll move that now to slide 8. This shows our cash flow performance for the first quarter. We began the quarter with $6.5 billion in cash and short-term investments on the balance sheet. You can see we generated $4.4 billion of cash from operating activities, had the $1.3 billion FCCL distribution and a working capital benefit of $600 million. We had capital expenditures and investments of $3.9 billion, and after paying our dividends and retiring debt of about $500 million, we ended the quarter with $7.7 billion of cash and short-term investments on the balance sheet. We've reduced our debt-to-cap ratio to 28% from 29% at the end of the year, so we're in great financial shape and well-positioned to execute our investment programs for the company.
That concludes the review of our financial performance. Now, I'll turn it call over to Matt for an update on our operations.
Matthew J. Fox, Executive Vice President-Exploration & Production
Thanks, Jeff. Good morning, everyone. So to begin, I'll provide first quarter operations update for each of our business segments, then I'll go over our production outlook for the remainder of the year and I'll conclude with a preview of some key activities to watch out for for the rest of 2014.
As we talk about each segment, you'll hear a common thread throughout the presentation and that's growth. As we progress through 2014 and into 2015, we expect to see growth in almost every segment of our business, and we're not just growing volumes, we're growing margins. Virtually all of our growing production will be at margins higher than our average margins today. So let's go to slide 10, our Lower 48 and Latin America segment, which continues to lead the way on strong growth for the company.
First quarter production averaged 507,000 BOE per day for this segment, which is a 7% increase from the first quarter of 2013. But more importantly, our crude production increased 16% over that same period. The biggest contributor to this growth was the Eagle Ford where we produced an average of 140,000 BOE per day during the quarter. Our daily peak rate for the quarter was 163,000 barrels a day, so we achieved good momentum after the weather problems early in the quarter. We currently have 12 operated rigs running in the Eagle Ford, and we've brought 48 wells online in the first quarter. We're transitioning to the 80-acre high/low development spacing we outlined at our analyst meeting a few weeks ago and we have additional pilots in progress that are testing further downspacing.
In the Bakken, we average 43,000 BOE per day and achieved a peak daily rate of 54,000 barrels a day in the first quarter. We are also performing pilot tests in the Bakken to optimize our drilling and development programs. Unconventional drilling and testing continues in the Delaware and Midland Basins in the Permian as well as in the Niobrara. It's still early days, but as we said at the analyst meeting, we remain optimistic about these emerging plays. In addition to our unconventional activities, appraisal drilling in the deepwater Gulf of Mexico continues at Tiber and Coronado and exploration drilling continues at Deep Nansen.
On slide 11, we'll give you some highlights from our Canada segment. Operationally, our Canada business performed very well in the first quarter. We produced 280,000 BOE per day, which includes a 9% increase in liquids production from the first quarter of 2013. Surmont 1 debottlenecking is progressing and our major project at Surmont 2 remains on schedule for first steam in the middle of next year. At the end of the quarter, the project was 68% complete. Christina Lake Phase E is approaching full capacity and Foster Creek Phase F remains on track for first production in the third quarter of this year.
As part of our Western Canada winter drilling programs, we successfully drilled 25 horizontal wells in the liquid-rich plays across our significant acreage position. This program continues to deliver good returns and holds a lot of drilling inventory. And we achieved a big milestone in the first quarter by drilling the longest horizontal well ever drilled in Canada, over 13,000 feet. That's an impressive operational and technological accomplishment and it shows how we're continuing to optimize our programs. We also continue to explore and appraise our unconventional plays in the Duvernay and Montney where we're seeing encouraging early results.
I'll now cover the Alaska segment on our next slide, slide 12. Alaska production was about flat sequentially at 200,000 BOE per day. We remain encouraged by the improved fiscal terms brought about by the passage of the More Alaska Production Act last year. And of note, we plan to spend more capital in Alaska in 2014 than we've spent there in the past three decades. This increased investment will mitigate declines in legacy fields and provide growth from new satellite fields into the future.
We're making good progress at our Drill Site 2S project in Kuparuk, the Greater Mooses Tooth 1 project on the Western North Slope and the 1H North East West Sak project. That 1H NEWS project is the third new project that's been initiated by the company since the passage of the More Alaska Production Act last spring.
We've had a good winter construction season at CD5, and we remain on track for startup in late 2015. We've drilled two exploration wells on the Western North Slope this winter, Rendezvous 3 and Flat Top 1, and we're in the process of evaluating those results. We'll resume LNG exports at our Kenai plant with a contract signed to deliver six cargoes in 2014, with the first shipment next month.
In April, enabling legislation was passed by the state legislature to allow the State of Alaska's equity participation in the AKLNG project, and this is a positive step forward for the project but there's still a lot of feasibility work to do and we hope to move into pre-feed in the near future. Alaska has become an attractive area for investment. We've got a lot of activity underway that we expect will provide additional growth opportunities for this segment in the future.
I'll next cover our Europe segment on slide 13. Like the Lower 48, this segment recovered well from some very challenging weather conditions late last year and early in the quarter. Production for the quarter averaged 220,000 barrels a day, which was about 12% higher sequentially. At our last quarterly call, we discussed the startup of Ekofisk South and Jasmine. Eko South, we're ramping up volumes in conjunction with drilling activity. At Jasmine, we recovered from some minor startup delays and averaged 25,000 BOEs per day for the quarter, and we brought a fifth well online at Jasmine in March. We also commissioned and started up our newest sour gas plant at the East Irish Sea.
Onshore construction activities are nearing completion at Eldfisk II for early 2015 startup, and offshore commissioning is ramping up at the Britannia long-term compression project for startup in the third quarter of this year. In Poland, we continue exploring in the Baltic Basin just to the west of Gdansk. We completed two vertical wells and sidetracked one of them horizontally during the first quarter. We are currently completing the horizontal section with an Eagle Ford style frac, and we intend to conduct an extended flow test later this year. As you can see in the bottom left of the chart, there's a heavy turnaround activity planned in the U.K. during the second and third quarter, which I'll discuss in a bit more detail in a later slide. So, our Europe segment is positioned for growth from high margin production this year.
And finally, let's look at our Asia Pacific and Middle East segment on slide 14. In this segment, we produced 319,000 BOE a day, 9% higher than the fourth quarter. And over this period, we also saw a 20% increase in higher margin liquids for this segment. Our 1Q planned turnaround at Train 7 in Qatar was completed ahead of schedule. In Indonesia, we achieved first gas at the South Belut project in April, which is the fifth phase of Block B's oil and gas development. We also achieved first oil in February at Siakap North-Petai and our non-operated Gumusut project is progressing toward startup in the third quarter of this year.
At Kebabangan, our topsides are scheduled for sail away in the second quarter and we're on track for first production by the end of this year. In exploration, we drilled a successful appraisal well in Malaysia at Limbayong-2 and we remain encouraged by our findings there, so there's clearly more growth potential in our Malaysia business. APLNG also remains on track for a mid-2015 startup. On a combined downstream and upstream basis, we were 67% complete at the end of the first quarter.
Our appraisal programs continue in Australia at the Browse Basin and at the Barossa field for wells spud in March and April respectively. Both of these wells should TD later in the second quarter. We expect this segment to provide significant production growth over the next couple of years.
Before I move to the next slide, me briefly touch on our other international segment. The key activity in this segment is exploration related. In Senegal, we spudded the first well two weeks ago. In Angola, our rig is now on transit to Block 36, and we expect to spud the [ph] Kamush (18:35) well late this quarter or early in the third quarter.
I'll cover our production outlook now on slide 15. We showed this slide at our analyst meeting last month. We slightly exceeded our guidance for first quarter volumes, but otherwise, our expectations are unchanged. As you can see, we expect production to drop during the second and third quarters due to seasonal maintenance activities across our operations. And on the left side of the chart is a list of the key turnarounds and tying activities for the next two quarters. This activity will start late in the second quarter beginning in the U.K., but the majority of our turnaround activity will occur in the third quarter. And these turnarounds impact almost all of our segments. The key activities in the third quarter will be in Alaska, Canada, the U.K., and the Bayu-Undan field in the Asia-Pacific region. Bayu-Undan is particularly noteworthy as this is a 36-day shutdown that includes brownfield activity for the tying in of two new subsea wells.
By the fourth quarter, our seasonal maintenance should be complete and additional projects should be coming online and we expect to exit the year at or above 1.6 million BOE a day. Full-year production guidance for continued operations is 1.51 million BOE to 1.55 million BOE a day, excluding Libya. And this is unchanged from our prior guidance and in line with our 3% to 5% production growth target. At this point, the biggest uncertainty in the range is the startup of our non-operated Gumusut project in Malaysia.
I'll now wrap up my comments with what to watch for in 2014. There are several activities underway to drive growth. Major project startups are expected at Gumusut, Foster Creek Phase F, Kebabangan, and our Britannia long-term compression project. These are important activities that should impact our 2014 exit rates and drive 2015 performance.
We also expect to continue growth both in the Eagle Ford and the Bakken. We laid out some development program details at the recent analyst meeting and raised expectations for these plays over the next few years. We'll continue our North American unconventional exploration and appraisal programs with a focus on the Permian and Niobrara. We'll also test our unconventional play in Poland with the extended production test that I spoke about. The company also farmed into three additional blocks in Colombia last year, where exploration will commence in the second half of 2014 to test the prospectivity of the La Luna shale. Gulf of Mexico deepwater drilling continues at Tiber, Coronado and Deep Nansen. And we're also preparing to begin our operated drilling program late this year or early next year. Finally, as I mentioned earlier, we'll begin exploration drilling in Senegal and Angola this year. And if successful, these programs would be a catalyst for growth into the next decade.
So here's what I hope you heard from our comments today. 2014 is off to a good start. We fully recovered from some weather and startup delays early in the first quarter and exited the quarter in a strong position to deliver on our volume expectations for the year. Our unconventional programs are performing very well, and our major projects are ramping up or progressing toward startup. We have another year of significant second and third quarter turnaround activity, but we are optimistic about achieving a 3% to 5% production growth in the year and momentum will build to continue that growth into 2015 and beyond. Our exploration activity is focused on drilling and testing a high-quality set of conventional and unconventional prospects, and we should have a lot to update you on in the coming months.
So this ends our prepared remarks, and we'll turn over for questions. Thank you.
QUESTION AND ANSWER SECTION
Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] And our first question is from Paul Cheng of Barclays. Please go ahead.
<Q - Paul Cheng - Barclays Capital, Inc.>: Hey, guys. Good morning.
<A - Jeff Sheets - ConocoPhillips>: Good morning, Paul.
<A - Ellen DeSanctis - ConocoPhillips>: Good morning, Paul.
<Q - Paul Cheng - Barclays Capital, Inc.>: Matt, on Foster Creek, it seems like it has been facing some operating issue. Gas-oil ratio has been up, and the cost has been quite high. Can you give us an update on what is the game plan and how confident you are that you can return that operation into, say, a couple of years ago kind of operating cost structure?
<A - Matt Fox - ConocoPhillips>: Yeah, these are short-term issues that we anticipated would happen as the steam chambers coalesced, and you expect to see steam-oil ratios increase under those circumstances. But the operator has a good plan in place to regain the steam-oil ratios that Foster Creek used to exhibit. And as we add Foster Creek Phase F and move steam from some of the more well-developed steam chambers to new steam. So we feel pretty confident that Foster Creek will return to the high performance that we've seen in the past there.
<Q - Paul Cheng - Barclays Capital, Inc.>: Jeff, can you give us an update or are there any updates at all related to the other sales planned in Canada or for the oil sand?
<A - Jeff Sheets - ConocoPhillips>: We've said on several occasions that we'll continue to look for opportunities to lighten our position in the oil sands, but that's just something that we're going to continue to watch. There's no update on that process, Paul, and there's nothing that's in our plans for 2014 in that regard.
<Q - Paul Cheng - Barclays Capital, Inc.>: Can I just sneak a real quick one for Matt?
<A - Jeff Sheets - ConocoPhillips>: Okay. Go ahead.
<Q - Paul Cheng - Barclays Capital, Inc.>: Matt, from the M&A standpoint, if you're looking at your portfolio in the upstream, is there any particular location that you think you may want to be more aggressive in acquiring additional acres?
<A - Matt Fox - ConocoPhillips>: Paul, of course, we're always looking to add opportunities to our portfolio. We're focused on doing that organically, and our exploration teams are out there all the time looking for high-quality acreage that we can add early in the life cycle. So, yeah, of course, we always want to take opportunities to strengthen the portfolio, but it's all about organic-led growth for us.
<Q - Paul Cheng - Barclays Capital, Inc.>: So there's no really any particular region or area that you think that you really have a hole and you want to be substantially step-up the land acquisition strategies?
<A - Matt Fox - ConocoPhillips>: There's no region where, I think, really we have a particular hole, and I wouldn't want to go into any specifics of the areas that we're looking at. It wouldn't be wise to do that.
<Q - Paul Cheng - Barclays Capital, Inc.>: All right. Thank you.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Paul.
Operator: Thank you. Our next question is from James Sullivan of Alembic Global Advisors. Please go ahead.
<Q - James Sullivan - Alembic Global Advisors LLC>: Hey. Good morning, guys.
<A - Jeff Sheets - ConocoPhillips>: Hey, Jim.
<A - Matt Fox - ConocoPhillips>: Good morning.
<Q - James Sullivan - Alembic Global Advisors LLC>: Good afternoon, actually. I just wanted to hear if you guys have had any plans on reporting results. I know during the analyst day, you talked about ongoing spacing test in the Bakken testing, I think, down to maybe four middle Bakken wells per spacing unit out there. Is that an ongoing test, and do you have a timeframe when you might have results on that?
<A - Matt Fox - ConocoPhillips>: Yeah, James, we have. I think it's about eight operated different pilot - operated pilot tests going on in the Bakken in particular, and we have some of our partner operated areas in the Bakken are testing different well spacings in different horizons. The timeframe, it takes a bit of time to really get results that you can feel confident about, and so I would say over the next year or more before we get really definitive results that would drive conclusions on the well density.
<Q - James Sullivan - Alembic Global Advisors LLC>: Okay. That's great. And then I just had two kind of housekeeping type ones on your costs. Obviously, you guys had a pretty good performance this quarter on production and in other areas, but two really jumped out at me were the SG&A and the interest, net interest numbers. And I was a little confused on the interest number. I know you guys paid down a bit of debt, but I've been under the impression that the capital interest - capitalized interest number was going to come down with cash you're getting out of the portfolio, yet the net number was pretty low. And then just the SG&A number, is there anything driving those and are those sustainable rates, running rates?
<A - Ellen DeSanctis - ConocoPhillips>: James, we're looking at a couple of things here. Hang on a second.
<Q - James Sullivan - Alembic Global Advisors LLC>: Sure.
<A - Jeff Sheets - ConocoPhillips>: The net interest number is higher than it was. I'm not sure what really your question is, and we do expect interest expense to be higher because of the fact we're no longer capitalizing interest and you see that in the first quarter. So I'm not sure if I'm following your question there, James.
<Q - James Sullivan - Alembic Global Advisors LLC>: I think I was just looking at kind of sequentially at the numbers. I mean yeah, it was up over Q1 2013.
<A - Jeff Sheets - ConocoPhillips>: Yes, I think in Q4 it's roughly the same number and you can just have slight variations during the quarter.
<Q - James Sullivan - Alembic Global Advisors LLC>: Okay. Great. Then on the G&A number?
<A - Jeff Sheets - ConocoPhillips>: G&A can also be a little bit lumpy as well quarter-over-quarter. I think we don't try to give any guidance separate for production and operating costs and for G&A. What we said back at our analyst presentation, as you recall, is that we see the combination of those two being $8.5 billion for this year, which is little bit higher than last year, otherwise just ramping up with growth.
<Q - James Sullivan - Alembic Global Advisors LLC>: Okay. Great. Thanks, guys.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, James.
Operator: Thank you. Our next question is from Doug Terreson of ISI. Please go ahead.
<Q - Doug Terreson - International Strategy & Investment Group LLC>: Good morning, everybody.
<A - Jeff Sheets - ConocoPhillips>: Hey, Doug.
<A - Matt Fox - ConocoPhillips>: Hello, Doug.
<A - Ellen DeSanctis - ConocoPhillips>: Good morning, Doug.
<Q - Doug Terreson - International Strategy & Investment Group LLC>: Profitability and margins were very high in the quarter and maybe even at a record level even after normalizing for price, as I think Jeff demonstrated, and on this point, I wanted to see if you'd comment on a couple of things. First that the trend in cost across the global portfolio, what are you seeing there; two, your lifting status in the most recent period; and three, was there any other regional profitability mix factors, either on the oil or the gas side outside of Jeff's comments on Lower 48 that stood out in the period?
<A - Jeff Sheets - ConocoPhillips>: I would say, we made some comments about the obvious things. Prices, of course, as you pointed out were a big driver this quarter, in particular natural gas prices. But underlying the margin growth is still this same thing we've been talking about, the movement of our portfolio to more liquids and to more production in areas where tax rates are generally lower, and that's the underlying effect which we said was still around 5% this quarter. Not having Libya volumes in the portfolio does make a 2% or 3% difference in cash margins year-over-year for us this year and, of course, the fact that we are able to sell gas at strong prices and have marketing gains helped this time as well.
In terms of other impacts, we mentioned that there were some minor impacts on lift timing this quarter. Overall lift timing was a negative on earnings, mostly in the Asia Pacific area. It probably impacted Asia Pacific earnings by the order of $40 million to $45 million in terms of lift timing, and with relatively smaller impacts across the other segments. But other than those things, there wasn't really anything very anomalous in the numbers. You asked about kind of trends on cost, kind of like on the previous question, what we are seeing is costs are going up as production is going up, but all that is covered by the fact that we're producing higher-value product. So overall cash margins are going up like we've been talking about.
<Q - Doug Terreson - International Strategy & Investment Group LLC>: Sure. And then, Matt, you talked about with Alaska where you guys are obviously one of the leaders up in the State, and while it might be early, my question is whether or not the improvement in your opportunity set appears likely to be significant enough to be able to stabilize your output up there, meaning what I'm trying to gauge is whether or not Alaska can end up being significant enough to represent another layer of growth for the company over a reasonable period of time?
<A - Matt Fox - ConocoPhillips>: Yes, I mean we are the biggest producer up there, as you know, Doug. And this change in the fiscal regime has opened up opportunities there to stabilize the decline from our overall asset base. Our asset base up there declines about 7.5% a year. So the development activity that we have going on, just in-fill development drilling and then the major projects that we're kicking off the engineering for and moving toward sanction, we're hopeful that we could stabilize Alaska production. And depending on how things play out as we put these development plans together, there's a possibility that we could see growth in Alaska. But even just stabilizing production in an asset of that size and that maturity would be a pretty good accomplishment, and I think that's achievable over the long run.
<Q - Doug Terreson - International Strategy & Investment Group LLC>: Okay. Great. Thanks a lot.
<A - Matt Fox - ConocoPhillips>: Thank you.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Doug.
Operator: Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead.
<Q - Paul Sankey - Wolfe Research, LLC>: Hi. Good morning. Good afternoon, everyone. Matt, thanks for your comments. I had a kind of high-level question about your acceleration in the Eagle Ford and maybe the Bakken too. How representative do you think you are of the wider competition that you have in those areas? I guess what I'm driving at is to an extent you were slower to ramp-up than some of your competitors, but now have at the analyst meeting put through a significant increase in your outlook for these areas. Do you feel like that represents what everyone's seeing or that you're going to be acting and moving much faster than your competition? And I guess I'm also thinking of any geologic implications you think about where you're located and what you're seeing against what would be the wider trend in the play? Thanks.
<A - Matt Fox - ConocoPhillips>: Yes. That's a good question, Paul, for - as you know that there's quite a lot of geologic. Even though all these things are essentially shales, there's quite a lot of variability geologically as you move across the Bakken and as you move across the Eagle Ford. We think that the acreage that we have in the Eagle Ford and the Bakken is right in the sweet spot. [indiscernible] (34:49) in the Bakken is pretty clearly the sweet spot. The area where we have the thermal maturity and thickness and pressure and geologic characteristics of our Eagle Ford position is strong. So I wouldn't expect our results to be the same as everyone else's. I would expect that hopefully as we continue this development, that our returns will be higher than the average returns, because of the position in the sweet spot. So you're right, we didn't ramp up the pace as fast as some others did, and we did that very intentionally. We'd rather do it right than do it fast and we are focused on maximizing value. And I think that the strategy that we've adopted in both of those plays is going to prove out to be the best long-term strategy.
<Q - Paul Sankey - Wolfe Research, LLC>: Which I guess would imply that your volume growth in those plays will outpace the volume growth in the wider play?
<A - Matt Fox - ConocoPhillips>: I mean that is very dependent on how many rigs people choose to run. So I couldn't say if that's going to be the case for sure, but we are going see significant continued growth in both of those plays as we showed them a couple of weeks ago.
<Q - Paul Sankey - Wolfe Research, LLC>: I understand you can't say for sure but what's you're feeling about how others are behaving as regards in competition with you?
<A - Matt Fox - ConocoPhillips>: It's really hard to say, Paul, because I mean it depends on how quickly they've been growing so far, and then what they intend to do with their rig counts and I don't have insight into that. But we're in the middle of the sweet spots of both plays and have got a really clear sort of consistent strategy on how we want to execute that, and we're continuing to see upside in both of those plays that we will exploit over the next few years.
<Q - Paul Sankey - Wolfe Research, LLC>: That's great. And then just to close off, the follow up is how are costs particularly in the Eagle Ford but also the Bakken as regards the activity that you're undertaking, how do we look at that? Thanks a lot.
<A - Matt Fox - ConocoPhillips>: So was that operating cost or capital cost, Paul?
<Q - Paul Sankey - Wolfe Research, LLC>: Both please, but really I was thinking more operating but...
<A - Matt Fox - ConocoPhillips>: So our operating costs in both plays are really low. I mean, we're below $5 a barrel in operating costs and so there is fairly low operating costs. That's one of the things that contributes to the high margins, of course, along with the high liquids yield in both plays. On a capital cost basis, I mean there are for the sort of wells that we are drilling, the costs that we're seeing are pretty much in line with what the rest of the industry is seeing up there. So I will say that competitive on operating costs and on capital costs in both plays.
<Q - Paul Sankey - Wolfe Research, LLC>: Great. I'll leave it there. Thanks Matt.
<A - Matt Fox - ConocoPhillips>: Thank you.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Paul.
Operator: Thank you. Our next question is from Ed Westlake of Credit Suisse. Please go ahead.
<Q - Ed Westlake - Credit Suisse Securities (USA) LLC (Broker)>: Yeah, two questions probably for Matt. Firstly, on the Bakken, you said a couple more years before you get definitive results to think about well density and appreciate nascent anticline natural fractures, and probably some of these areas is slightly off piece of that. Just on - what is it that you're trying to see? Is it sort of the year two and year three declines to try and get a sense of the economics of some of these wells? I mean obviously, we have data from some of these wells for about a year so far.
<A - Matt Fox - ConocoPhillips>: Yeah, that's right, Ed. When you tighten up the well spacing, you sort of really expect the early period of production to look similar on wells at that tighter spacing and wider spacing. So it's not until you've got a sense of the decline characteristics that you can really get full understanding if the wells are interfering with each other and competing for the same oil or if they're not, and so you're right, you need a few years to get confidence in the overall type curve characteristics as you tighten up. You've got to be careful not to allow the pilot test to flatter, to deceive, because in the earlier days, you do expect to see similar performance from wells on tighter spacing. So that's why I was saying that we need some time to make sure that we are actually developing incremental reserves and adding incremental values with tightening well spacing up.
<Q - Ed Westlake - Credit Suisse Securities (USA) LLC (Broker)>: So a little bit premature to have EUR that you can have confidence in?
<A - Matt Fox - ConocoPhillips>: Yeah, I think so.
<Q - Ed Westlake - Credit Suisse Securities (USA) LLC (Broker)>: And then on the Permian, I mean one of the debates obviously in the refining space is this superlight crudes that are coming out of the shales. Obviously, you have some of that in the Eagle Ford with condensates. You're doing tests in the Delaware Basin and also in the Midland Basin. So I'm just wondering if there's any differences in terms of the - I mean, obviously people quote crude NGLs and gas but they probably don't speak enough about the quality of the crudes coming out. Can you give us some color on what you're seeing in terms of those tests, because obviously it will affect the infrastructure that's required and also the pricing of the molecules.
<A - Matt Fox - ConocoPhillips>: Yes. This may not be a very satisfactory answer, Ed, because as you go through this 4,500 feet of sort of stack and opportunity that exists in the Delaware Basin in particular, you get a very significant variation from - in some areas, it's a gas with a high liquids yield; in some areas, it's a relatively low API oil; in other areas, you've got a strong condensate yield. So it's going be very variable, but it's clear that over the long run, there's going to be quite a bit of gas, NGLs, condensate - that's going to grow in production in the Permian Basin as a whole. And as our understanding and the industry's understanding of that matures, that will have implications for what sort of off take and infrastructure requirements there are to fully evacuate all of these products from the Permian area.
<Q - Ed Westlake - Credit Suisse Securities (USA) LLC (Broker)>: And let more on the Delaware than the Permian?
<A - Matt Fox - ConocoPhillips>: [indiscernible] (41:10) but even in the Midland Basin too. There's going be some significant variation there. But I think that my sense is a wider variation in the Permian than the Delaware but time will tell.
<Q - Ed Westlake - Credit Suisse Securities (USA) LLC (Broker)>: Okay. Thanks.
Operator: Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead.
<Q - Blake Fernandez - Howard Weil, Inc.>: Hi, folks. Thanks for taking the question. Back at the analyst day, you kind of outlined the production profile where the U.S. unconventionals were increasing, and it seemed like you were decreasing Europe and Western Canada, if I'm not mistaken, to kind of accommodate to where overall things remained pretty much in line with your previous guidance. My question, I guess, is what happens to those European and Western Canadian projects? Is that simply being deferred? And I guess what I'm wondering is do we have potential into 2015 for there to be an opportunity to maybe go toward the upper end of the 3% to 5% range on production?
<A - Matt Fox - ConocoPhillips>: We're very careful that if we are going to reduce capital in an area that is deferring, we're not going to lose opportunities. So the Western Canada, we've got huge inventory of opportunities there with the high liquids yields, and the European projects that we spoke about, those are deferrals. So both of those areas, for example, are retaining opportunities to add growth in the later part and then 2017 and beyond. So I think that we're making pretty judicious capital allocation decisions that balance the short and the long-term growth potential in the portfolio.
<Q - Blake Fernandez - Howard Weil, Inc.>: Okay. So that's outer year, not necessarily next year then it sounds like?
<A - Matt Fox - ConocoPhillips>: Probably, but every year we sort of re-look at the portfolio. One of the beauties of our portfolios is the level of flexibility that we have and the level of optionality that exists. But in general, the ones that we're talking about are probably more than opportunities to continue growth beyond 2017, but we'll see.
<Q - Blake Fernandez - Howard Weil, Inc.>: Okay. Thanks for that, Matt. The second one, I apologize if this a little bit detailed, but I just want to make sure we understand from a modeling standpoint, the Kenai Alaska LNG from a reporting standpoint, I'm assuming obviously the earnings from that will simply drop into Alaska, but are there corresponding volumes associated with that? I guess I'm just trying to understand if this is just going to be simply margin expansion or if there will be both production and earnings increases?
<A - Matt Fox - ConocoPhillips>: So there will be both, but the production growth is relatively small. So each of those LNG tankers that we load in Kenai contain about 2.75 Bcf of gas. And our expectation is that about 40% of that or so will be equity gas, ConocoPhillips equity gas, and then there will be third-party gas that we're moving with those tankers as well. So there will be some production growth but annualized over the year, it's relatively modest; 4,000 barrels a day or something like that over the year, but we do get very good margins, good value from that business.
<Q - Blake Fernandez - Howard Weil, Inc.>: Okay. Thank you.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Mike.
<A - Matt Fox - ConocoPhillips>: Thanks, Mike.
Operator: Thank you. Our next question is from Doug Leggate of Bank of America. Please go ahead.
<Q - Doug Leggate - Bank of America Merrill Lynch>: Hey, guys. Thanks for getting me on. Jeff, can I start with the DD&A guidance for the year? Is that really going to be back-end loaded compared to what you did in Q1? I think at your analyst day, you said Gumusut and one or two others might be responsible for that, but what should we think about as the unit DD&A run rate at the end of the year when the production is online.
<A - Jeff Sheets - ConocoPhillips>: So we gave guidance, Doug, of $8.5 billion for DD&A for the year and like you've seen, we came in like $1.9 billion or so in the first quarter. It is going to be back-end loaded and really a few things drive that. One is Jasmine started up, it was ramping up in the first quarter. That's one of the things causing increases in DD&A. We're going to continue to see increases in unconventional production in the Lower 48 as we go through the year that will cause DD&A to increase. But probably the largest single item is the Gumusut start-up, which is more of a third quarter item for us, which causes that DD&A to be back-end loaded.
In terms of unit rates, you'll see that go a little bit higher. I don't have those just right off the top of my head here, but we still think the $8.5 billion number is the right number for the year and that you'll see that back-end loaded, a little bit higher numbers in the fourth quarter than the second and third quarter.
<Q - Doug Leggate - Bank of America Merrill Lynch>: [indiscernible] (46:10) So Q1 was about $13 and change and the average would be about $15 and change. So should we think something like a $16, $17 kind of number as Q4 order of magnitude?
<A - Jeff Sheets - ConocoPhillips>: Kind of order of magnitude, I think the way I tend to think about it more is that the DD&A doesn't apply to all of our production since you get equity barrels as well. So you've got, in our portfolio, about 200,000 barrels a day of equity accounting barrels, which don't have DD&A associated with them. So I'd say our DD&A is probably more like $15, $15.5 right now and that you may see that drift up a little bit as you go into the third and fourth quarters.
<Q - Doug Leggate - Bank of America Merrill Lynch>: Okay. Thanks.
<A - Jeff Sheets - ConocoPhillips>: We are going to be adding significant volumes in the fourth quarter in particular.
<Q - Doug Leggate - Bank of America Merrill Lynch>: Got it. Second one, my follow up, if I may, is just a quick one for Matt. Matt, over the years, there's been a debate between operators in the Eagle Ford on how you choke your wells. We've seen obviously EOG with some very, very strong rates and they are, obviously, in the lower pressure part the reservoir. There's others like Pioneer, I guess, which are a little bit south of you, in that same neighborhood as you guys are, are big advocates of kind of choking back to retain reservoir quality and so on. I'm just wondering if you could share with us how you are approaching that in terms of how we should think about the well rates that you're getting out? Are you chocking back, are you trying to manage towards that longer term recovery or how do you think about it? And I'll leave it there. Thanks.
<A - Matt Fox - ConocoPhillips>: Yeah, yeah, so we're more in the latter camp of managing the early rates, and that's driven by a few different things. We don't build our single well facilities so that they can handle very high peak rates that you're only going to have for a few weeks or a few months even. And so, that's the reason for doing it. We want to make sure that we keep all the proppant in the hole. We don't want to be having such a high draw down that we're damaging our completions, and so we do choke back quite significantly. I mean in the early month, we can have [ph] given (48:21) head pressures over 7000 PSI choked back, and so we manage it to make sure that we're not oversizing the facilities and to make sure that we're not damaging the completion. And there is some evidence that that's the right long-term thing to do as well, not only sort of prudent from an operations perspective so that's the approach that we take.
<Q - Doug Leggate - Bank of America Merrill Lynch>: Is that significant in terms of the upfront decline rate, Matt? I mean does that slow you down quite a bit for a meaningful period or is it not really that material? I'm just trying to get a feel for what your decline curves might look like on those wells.
<A - Matt Fox - ConocoPhillips>: So we can - on some of our wells, we would be maintaining essentially flat production for several months. And so over those months, you are choking the reservoir back. So it has implications for the first year average rate, and then so that does have implications for the observed decline rate. I think that's what you're getting at.
<Q - Doug Leggate - Bank of America Merrill Lynch>: Yes, that's exactly right. Okay. That's helpful. Thanks a lot.
<A - Matt Fox - ConocoPhillips>: Thank you.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Doug.
Operator: Thank you. Our next question is from Faisel Khan of Citigroup. Please go ahead.
<Q - Faisel Khan - Citigroup Global Markets Inc. (Broker)>: Thanks. Good afternoon.
<A - Jeff Sheets - ConocoPhillips>: Good afternoon, Faisel.
<A - Ellen DeSanctis - ConocoPhillips>: Good afternoon, Faisel.
<Q - Faisel Khan - Citigroup Global Markets Inc. (Broker)>: Just going back to your comments on the Alaska LNG project, you talked about enabling legislation passed in April. Is there any change from the comments you guys made at your analyst meeting in terms of sort of the type of spend pattern you would see for this project over the next few years, with this enabling legislation having been passed?
<A - Jeff Sheets - ConocoPhillips>: No, we were anticipating that the legislature would support the Governor's approach to this. So our view of the spend profile for AKLNG hasn't really changed. We're hopeful that we will get to move into pre-feed. I mean we've already selected the high-level concept, and I think I've discussed that in previous calls. But we need to get into pre-feed hopefully in the second quarter here, and that will last 12 or 18 months. And then, we'll move into the feed program, which will take two or three years. So really the sanction of the project, we're probably looking out to 2017 or 2018 before we would actually sanction the full-scale project. It takes a bit of time to get through the engineering of something that's of this sort of scale, as you can imagine.
<Q - Faisel Khan - Citigroup Global Markets Inc. (Broker)>: Okay. Got it. And then just wanted to see if there's any sort of read through for your guys drilling program in Angola with sort of recent results by the Cobalt on this Orca DST? Is there anything that changes? So is there anything in that data that changes sort of your outlook for the prospects you have for the end of this year?
<A - Jeff Sheets - ConocoPhillips>: Not really. I mean the way we've been encouraged by the results that other operators have had in the area. We picked up the acreage before the play had been tested, but the results that we've had have been - sort of seeing other operators announce have given us encouragement that we're in the right part of the play and we'll know that before we get to the end of this year. We'll have the first well done hopefully before the end of the year, but no change in our views really as to what the materiality and prospectivity is on that Angola position.
<Q - Faisel Khan - Citigroup Global Markets Inc. (Broker)>: Okay. Just last question for me. On APLNG, you've given some detail on that at the analyst meeting, but in terms of the progress on that facility, is it still - are all the major components for that facility sort of coming online and are the producing wells sort of also ramping up the way you anticipate? I just want to make sure that there's sort of no risk here, that the project sort of slips like we've seen with a few others in that part of the world?
<A - Jeff Sheets - ConocoPhillips>: No, we're still pretty confident we're hitting our milestones. The actual LNG plant itself on Curtis Island - I'm not sure if we've shipped all of the modules already, but if we haven't, it's pretty much all of the modules. So we're on track. We've built these plants before, so we feel pretty confident that we are on schedule there. And the upstream part of the project, we still have a lot of work to do there. We've got a lot of rigs running. We're commissioning our gas plants, our [ph] well (52:53) handling facilities. But we are still confident that the middle of 2015 is we should have the LNG plant itself, the first train ready, and we should have the gas that we need to get that fully commissioned. So I would say that we feel that the project is on track.
<Q - Faisel Khan - Citigroup Global Markets Inc. (Broker)>: Understood. Thank you for the time. I appreciate it.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Faisel.
Operator: Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead.
<Q - Roger Read - Wells Fargo Securities LLC>: Yeah. Good morning or good afternoon as the case may be.
<A - Jeff Sheets - ConocoPhillips>: Hey, Roger.
<Q - Roger Read - Wells Fargo Securities LLC>: Hey, Jeff, question for you. Look at Q1 results and, obviously, we can strip out the payment from Canada, we can strip out the working capital advantage here in the quarter. Yet even after you do that, free cash flow is essentially breakeven, which given how you've structured the company for the next several years, that's a real positive sign. As you look at the projects that are coming online kind of a midpoint of 3% to 5% volume growth and 3% to 5% margin, does a quarter like this indicate any sort of - maybe you get there sooner in terms of the free cash flow matching, or, I should say, free cash flow - cash flow out matching cash flow in and getting to sort of a neutral or slightly positive free cash flow situation?
<A - Jeff Sheets - ConocoPhillips>: Yes, in that we had a quarter with very strong pricing. We had Brent at near $110 still and WTI above a $100, and very strong North American natural gas prices, of course, which helps our cash flow numbers. I think the way we like to think about it, though, is we've got the growth in production and margins happening, which are going to get us to that neutrality point across a wide range of prices. And how quick we get there can be influenced by prices, but by - as we talked about at the analyst presentation, by 2017, we've added considerable production at higher margins and are going to have the size of cash flows that are across a pretty wide range of commodity prices are going to get us to that neutrality point. Yeah, that could back up to 2016 if prices were higher, but we don't count on having prices like we saw in the first quarter long-term in order to - as the basis for our plans.
<Q - Roger Read - Wells Fargo Securities LLC>: Okay. That's helpful. And then from a strictly operational standpoint, heavy turnarounds last year in the summer in the North Sea, again this year. Maybe Matt, the question is for you. Is that going to be typical for your North Sea production over the next year - couple of years or are you getting past sort of a pig in the python moment here, two big years of maintenance in the North Sea in the summertime?
<A - Matt Fox - ConocoPhillips>: It's more of the pig in the python thing for the North Sea. We had a huge turnaround last year in Norway, the biggest we've ever had. There's no significant turnaround going on in Norway this year or next year, because we have Norway on a three-year cycle. They'll be some short down time at Eldfisk to tie in for the new Eldfisk II project, but it's a handful of days for that. This year's turnaround is little bit less than last year's. I think it's about 3% less in overall turnaround activity. But you're right, these have been two relatively big years in turnarounds and they are somewhat anomalous from that perspective.
<Q - Roger Read - Wells Fargo Securities LLC>: Okay. That's helpful. Thank you.
<A - Matt Fox - ConocoPhillips>: Thank you.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Roger.
Operator: Thank you. Our next question is from Pavel Molchanov of Raymond James. Please go ahead.
<Q - Pavel Molchanov - Raymond James & Associates, Inc.>: Hey, thanks for taking my question. In your exploration section, you have a pretty extensive set of upcoming catalysts. And I know that historically you've talked about kind of shifting away from high-impact wildcatting. Is 2014 somewhat of an exception or do you think you'll continue this exploration run rate, especially deepwater going forward?
<A - Matt Fox - ConocoPhillips>: No, I think we'll continue it. I mean there are some really interesting wells that we're drilling there this year, but we've built an exploration portfolio that has a good mix of unconventional and conventional opportunities with - that's a portfolio that allows us to do this. So a significant testing this year, but continuing that over the next several years in the Gulf of Mexico and elsewhere. I mean we're continuing to add to the exploration portfolio. So I'm hopeful that we'll have the 2015 and the years beyond that, we'll still have an exciting exploration and appraisal program to exploit.
<Q - Pavel Molchanov - Raymond James & Associates, Inc.>: So in the context of kind of flattish CapEx in total, do you anticipate that your offshore spending just globally will be up year-over-year in 2014 or...
<A - Matt Fox - ConocoPhillips>: No. Well, on average, we'll say that it's about 15% of our overall capital, about $2.5 billion a year and some years have been a bit higher. This year, it will be at about $2.1 billion for example. So it will fluctuate from year to year, but it's going to average, I think, around that $2.5 billion for the E&A program overall. And of course, the split between conventional, unconventional, deepwater and shallower water, that's clearly going fluctuate as prospects mature and we get to the drilling phase of the life cycle, but on average about $2.5 billion a year.
<Q - Pavel Molchanov - Raymond James & Associates, Inc.>: Okay. Thanks very much.
<A - Matt Fox - ConocoPhillips>: Thank you.
<A - Ellen DeSanctis - ConocoPhillips>: Thanks, Pavel. We'll take one more question, if there's one, and then cut it off here.
Operator: Our last question is from Asit Sen of Cowen & Company. Please go ahead.
<Q - Asit Sen - Cowen & Co. LLC>: Thanks. Good afternoon, guys.
<A - Jeff Sheets - ConocoPhillips>: Good afternoon.
<A - Ellen DeSanctis - ConocoPhillips>: Good afternoon.
<Q - Asit Sen - Cowen & Co. LLC>: So I have a question on Malaysia, and Malaysia is a decent part of the growth equation over the next 12 to 18 months, driven by Gumusut and KBB. How much Malaysian volume is embedded in the 2014 production guidance, and could you provide what is the incremental contribution from Malaysia expected in 2015?
<A - Matt Fox - ConocoPhillips>: Off the top of my head, I'm not 100% sure of what the 2014 - I would say it's around 20,000 barrels a day for 2014, and that would be higher, but I can't remember how much higher in 2015, maybe another 20,000 barrels a day by the time we get to 2015. So that's a significant part of the growth and it's high-margin growth, but how much we produce this year in Malaysia is very dependent upon when Gumusut starts up. But it's a significant part of growth and it's good high-margin growth. And so we have S&P on production. We have the Gumusut early production system on just now. We'll bring on the full floating production system for Gumusut hopefully in the third quarter of the year. We'll bring on Kebabangan late in the fourth quarter. We still have the Malachi project in execution just now, and we've got four or five other discoveries in the area that we're moving forward through the appraisal and engineering stage. So it's a good piece of business for us, and it's going to contribute to both our production and margin growth over the next few years.
<Q - Asit Sen - Cowen & Co. LLC>: Thanks.
Ellen R. DeSanctis, VP-Investor Relations & Communications
Thanks, Asit. Appreciate it. And why don't we call it good there? By all means, call IR if you have any follow-up questions. Thank you so much for joining us, everybody, and thank you, Christine.
Operator: Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.