APA Corporation (APA) Q1 2012 Earnings Report, Transcript and Summary

Good afternoon. My name is Sarah, and I'll be your conference operator today. At this time, I would like to welcome everyone to the First Quarter 2012 Earnings Release Conference Call. [Operator Instructions] Thank you. Mr. Cassidy, you may begin your conference.

Thank you, Sarah. Good afternoon, everyone, and thank you for joining us for Apache's First Quarter 2012 Earnings Conference Call. This morning, we reported earnings of $778 million or $2 per diluted share. Adjusted earnings, which exclude certain items that impact the comparability of results, totaled $1.2 billion or $3 per diluted share. Cash flow from operations totaled $2.6 billion for the quarter. On today's call, we will have 3 speakers making prepared remarks prior to taking questions. First, we will hear from Steve Farris, our Chairman and Chief Executive Officer; followed by Rod Eichler, President and Chief Operating Officer; and finally, Tom Chambers, Executive Vice President and Chief Financial Officer. We prepared our quarterly supplemental data package for your use, which also includes a reconciliation of any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or pretax margins. This data package can be found on our website at www.apachecorp.com/financialdata. Today's discussion may contain forward-looking estimates and assumptions, and no assurances can be given that those expectations will be realized. A full disclaimer is located with the supplemental data package on our website. With that, I'll turn the call over to Steve.

Thanks, Patrick, and good afternoon, everyone, and thank you for joining us today. The first quarter of 2012 continued Apache's strong growth in production, earnings and cash flow. Our daily production during the quarter was up 7% from the first quarter last year adjusted for divestitures. And I want to point out that this growth came despite having about over 10,000 barrels of oil equivalent a day off during the quarter due to production disruptions, and Rod Eichler will get into more detail a little later in the presentation. Our corporate production growth expectations for the year remains strong between 7% and 13% over 2011 with a capital program that, I might add, that lives within our cash flow. We are continuing to build production momentum, and I'd like to mention just a few of the highlights of the quarter before I turn it over to Rod who'll give you a more detailed operational report. In the Permian Basin, we entered the quarter with 26 rigs running. We now have 31 rigs running, going to 34. We have had good results in the Wolfcamp horizontal and the lower Cline plays, and we continue to accelerate as we get after a Permian drilling and resource portfolio that is really second to none. In the Mid-Continent liquids play, we entered the first quarter with 6 rigs running and currently operate 22. We continue to have attractive and consistent results across a number of liquids plays from the Granite Wash, the Tonkawa, the Cleveland, the Marmaton, Cherokee and the Canyon Wash. Our drilling inventory in the Mid-Continent is very comparable to that in the Permian, and we are more than tripling our activity in order to translate that activity into production and cash flow today. Importantly, we have the asset strength to do this while still living within our cash flow in our Central region. We intend to unveil our Permian and Mid-Continent resource potential at our June 14 Analyst Day in Houston. In Canada, we're quickly transitioning our activity into an oil and liquids play focus. In our drilling during the first quarter, we've concentrated almost entirely on the Viking, the Bluesky, Montney, Glacier, Chinook and Beaverhill Lake plays, which have real running room across 6 million acres in that region. While this transformation unfolds, our current production in the region is still 83% gas, and our Canadian gas realizations continue to decline for the quarter, which contributed to a noncash write-down of the carrying value of our proved Canadian properties. And Tom Chambers will discuss this in greater detail in a few moments. Oil and liquid plays, we are locking on our Canadian acreage, rival those in the Permian and the Mid-Continent, and the fact that gas prices are low is not unique to Canada. Our longer-term gas solution is exporting to BTUs where they are valued, and that's why we're pursuing the Kitimat LNG project, which continues to progress toward FID. One change in our capital plans for the year in Argentina where our technical work has delineated about 650,000 acres in the oil window position in the Vaca Muerta shale. Most of it is either adjacent to or in the vicinity of the recent wells that have generated so much excitement down there, and our first test results have been very encouraging. And we have increased our region's capital program by 20% to accelerate our drilling and recompletion activity in this potentially very large oil resource play. And with that, I'd like to turn it over to Rod Eichler.

Thank you, Steve. We had another solid quarter of growth, and we're really just getting started. I'll begin with international as the bulk of our new volumes in the quarter came from the North Sea, where we completed the acquisition of Mobil North Sea Limited's Beryl and other fields at the end of last year. Production is up 67% year-over-year and 41% sequentially with plans in motion for continued growth. Apache assumed operatorship on December 31, including taking onboard 184 staff members from the previous organization to bring with them a wealth of experience and ideas for adding value. These fields had largely been in decline due in part to minimal investment from the prior operator who focused primarily on maintenance and compliance. As we did at Forties, we expect to reverse the direction of the production curve by acquiring and processing new seismic data, drilling wells and continuing workovers and other value-adding activities. Overall, the general infrastructure and platforms are in good shape, although we're dealing with obsolescence in certain areas, which isn't unusual for mature offshore assets. We recently drilled a new well from the Beryl Bravo platform, known as the BBP prospect, that we're currently completing and should have online later this month. Our team in Aberdeen is very excited about this one because we found virgin reservoir pressure in 2 of 3 zones containing more than 300 feet of net true vertical pay. This should be a very robust well and opens up further development opportunities. A 1,500 square kilometer 3D seismic survey is scheduled to commence during the third quarter, and we expect this program will significantly supplement the backlog of drillable locations on these newly acquired assets. This will be the first 3D acquired over the Beryl area licenses since 1997, and we are expecting a step change in the ability to image and interpret the very large and geologically complex structures in this area. Forties Field was off approximately 6,000 barrels a day during the quarter due to plant turnaround, ESP failures at 2 wells and the fact that no new wells came onstream to offset these disruptions. This is deferred production, and we expect to recover these volumes later this year. Also during the quarter, we completed our subsea development work at Bacchus. And the first horizontal development well commenced production last week, producing at an initial rate of 6,000 barrels of oil per day. A second well was spud and is drilling ahead for Jurassic objectives in the central and western parts of the Bacchus geologic structure. In Egypt, overall, we're producing to plan. Our quarterly gross BOE volumes are up 1% sequentially. But under the terms of our production sharing contracts, as oil prices increased, our net production is reduced as fewer barrels are required for cost recovery. Due to these terms, our net daily production in the first quarter was reduced by approximately 4,000 barrels oil equivalent per day primarily from the 16% increased oil price realizations, averaging nearly $124 per barrel compared with $107 a barrel at the preceding period. Operationally, we have more rigs running, 26 currently, than a year ago and more wells planned this year, 280 versus 262. Importantly, we're getting more development leases approved. So we're able to convert exploration success to production at a faster pace than last year. And we continue to have good results with drill bit. In our Qarun joint venture, 2 exploration successes at the Heba field commenced production at a combined rate of 1,300 barrels of oil per day. In total, 22 new producers came online during the quarter, contributing 5,600 barrels of oil per day. In our Khalda area concession, we made several significant discoveries. The Qasr-1X exploration well in the West Kalbasha Station [ph] tested at the daily rate of 5 billion cubic feet of gas per day and 4,800 barrels of 43-grade API of oil per day. In the Kronos field, the discovery well tested 22 million cubic feet of gas and 700 barrels of condensate per day on a 460-acre structure. At Karman [ph], a test of the lower Sapa yielded 1,100 barrels of oil per day. And in Khalda field, an exploration well proved up stack base in the lower Sapa and A and B sections testing 1,700 barrels of oil per day. Lastly, exploration of the lower Baharia and Mirakar-1X [ph] in the AG development lease, which has been acquired from BP, it counted 198 feet of pay. After fracture stimulation, the well produced 28 million cubic feet of gas per day and 600 barrels of condensate per day. We continue to progress the development of our assets in Egypt. Despite ongoing struggles in the quest for democracy, our operations have continued uninterrupted and are supported by our government partners, as evidenced by the issuance of new development leases, drilling permits and the ongoing process of the first [indiscernible] in 6 years. We're really optimistic for Apache's future in Egypt. Turning to Australia. We commenced 2 new contract sales at our Devil Creek gas plant on January 1. New contracts significantly boosted our average gas price for our region, up 58% from the prior quarter to $4.18 per Mcf. Two cycles resulted in deferred production of 4,000 boe per day during the period, but there was no lasting damage. Van Gogh production averaged 10,800 barrels of oil per day, and we continue to realize good uptime and reservoir performance. Pyrenees field average 14,400 barrels of oil per day in the quarter, below plan due to Cyclones Heidi and Iggy. Reindeer averaged 44 million cubic feet of gas per day for the quarter, and we have 2 additional Reindeer gas contracts coming on in 2013. One of the highlights from our drilling campaign is the BHP Billiton-operated Tallaganda gas discovery in which Apache has a 25% working interest. This well accounted approximately 160 feet of net pay in the objective Mungaroo sandstones. We are currently evaluating the data and looking with our partners to determine the next steps. At the Coniston oil development project, long lead items have been ordered, and subsea packages are being manufactured. Work is on schedule for start-up in the second half of 2013. The [indiscernible] development is also progressing with its first oil anticipated in the front half of 2014. Finally, in Argentina, production was up from the prior year's first quarter but down from the preceding quarter due to higher gas reinjection and shale [indiscernible], which is typical during the southern hemisphere summer months of January through March. Our price realizations were up substantially from year ago. Approximately 84 million cubic feet of gas per day of our production was sold under the Gas Plus program at an average price of $4.95 per Mcf during the quarter. Overall, our gas realization was up 37% to $2.98 per Mcf from a year ago. Oil realizations were also up, averaging $83 per barrel, a 38% increase. We've had no impact from the recent events involving the Argentine government and YPF. Our team in the country continues to have positive discussions with both federal and provincial authorities to identify and remove constraints toward developing new reserves and production. We continue to focus our exploration and development activities in Neuquén Basin where we hold 1.7 million acres in the prospective Vaca Muerta shale per weight, of which 650,000 net acres are in the oil play. On the Huacalera block, we see the well last year as primary objective of the Vaca Muerta shale. The secondary objective is in the [indiscernible] formations. We saw significant gas shales in all 3 formations, as well as El Contico [ph]. During the first quarter, we fracture-stimulated the well with testing beginning at the end of March. We will study those wells for the next couple of months to collect more vital data and determine steps for development. On the Quarta Vara block, a well we TD-ed last August to test the Vaca Muerta El Contico [ph] formations was also fracture-stimulated in the first quarter. We will soon place this well in a 90-day flow test before shutting it in to collect pressure data. We plan up to 8 rig completions in the Vaca Muerta formation this year with plans to permit up to 5 new drill locations, both vertical and horizontal, in the oil fairway. We expect to initiate this drilling in the third quarter. Now moving on to North America. We continue to ramp up activity in the Permian, where we are the second-largest operator in the basin. First quarter production averaged nearly 99,200 barrels of oil equivalent per day. 70% of the production was liquids, and 82% of that was black oil. This is a 3% increase in per day production from the preceding quarter and includes about 2,800 barrels of oil per day related to prior period adjustments, mostly associated with BP and non-operated true-ups. We averaged 28 operated drill rigs for the period, up 3 from the fourth quarter, drilling 147 vertical wells and 17 horizontals. We currently operate 31 rigs in the region, including 6 horizontals. We are running a 14-unit drilling program in the Deadwood area and continue to see positive results. In February, we commenced Phase 1 operations from the Deadwood gas plant, a joint venture with Crosstex Energy, immediately re-commit the facilities in the 90 million cubic feet of gas capacity. Phase 2 is expected come online this quarter and will be fully operational later this year. The plant capacity will be 50 million cubic feet of gas per day. We expect to drill third [ph] wells in Deadwood this year. Exploration drilling in the Cline Wolfcamp play is also underway. It's too soon to talk about results here right now, but we plan to provide more disclosure of our progress next month at our June 14 Investor Day. I'll move now to our Central region of Oklahoma and Texas Panhandle. We have more than doubled our position in the Anadarko Basin wash play fairway to nearly 550,000 net acres with the completion of the Cordillera acquisition on Monday. With it, we've increased Apache's exposure to the prolific Granite Wash, Tonkawa, Cleveland and Marmaton gas condensate oil plays. We now operate 22 drilling rigs in Anadarko Basin and are contracting for another 2. A number of notable horizontal wells were completed during the first quarter. On Apache's legacy acreage, we drilled 3 Cleveland wells and averaged 400 barrels of oil per day and 850 Mcf of gas for the first month. Two Marmaton wells averaged 340 barrels of oil and 7.5 million cubic feet of gas per day and 3 Granite Wash wells, which averaged a daily rate of 475 barrels of oil and 5.6 million cubic feet of gas per day. We also continued the successful Cherokee program, drilling and completing 2 wells that produced an average of 250 barrels of oil and 350 Mcf per day for the first month. On the newly acquired properties, 24 wells were drilled and completed during the quarter. Among them were the Cleveland well, which averaged 375 barrels of oil and 400 Mcf per day; 2 Tonkawa wells that averaged 475 barrels of oil and 1.1 million cubic feet of gas per day; and 5 Granite Wash wells that averaged daily rates of 240 barrels of oil and 8 million cubic feet of gas. We also had a very impressive Marmaton well coming on with a 30-day rate of 11 million cubic feet of gas per day and 800 barrels of oil per day. Offsets to this well are currently being completed. In April, net productions from the Cordillera assets averaged approximately 21,900 barrels of oil equivalent per day, up 22% from January. As with the Permian region, we will have more detailed disclosure of our Central region assets and opportunities on June 14. Sequentially, our lower first quarter daily production reflects our low fourth quarter rig count and asset divestments of approximately 40 million cubic feet of gas per day and 200 barrels of oil per day from our former East Texas properties. This will certainly be reversed in the second quarter with the addition of Cordillera and overall accelerated drilling program. Turning now to the Gulf of Mexico shelf. We drilled 10 wells during the quarter with a 90% success rate. Our production for the region overall and for oil is ahead of plan of approximately 1,900 barrels of oil equivalent per day and 3,800 barrels of oil, respectively. Like other operators, we are dealing with third-party platform and pipeline issues, which offset higher volumes for property we acquired in 2010. New pipelines are being laid in the Ship Shoal, South Marsh Island, Vermillion and Matagorda Island areas, which should help to address past pipelines shut-ins. We are seeing some settling down in the regulatory environment. The Bureau of Safety and Economic and -- Bureau of Safety and Environmental Enforcement, or BSEE, is spreading the processing of drilling permits around other district offices, which is helping to alleviate the backlog built up since Macondo. I'm proud to point out that Apache was the first Gulf of Mexico operator to submit and receive Safety and Environmental Management System, or SEMS, audit plan approval. Implementation of that plan officially kicked off on Monday, April 30. Notable activity during the quarter included the commissioning of a new platform of Main Pass 308. We drilled 3 wells, which, combined, are producing 900 barrels of oil and 5 million cubic feet of gas per day. A fourth well is drilled, and we're testing -- we're currently testing it, and we're prepared to drill ahead on a fifth. We anticipate drilling 8 wells total and reaching up to 3,200 barrels of oil equivalent per day of production by the end of this year. Following a routine inspection, Apache detected corrosion at Grand Island 43 Complex [ph]. Approximately 5,500 barrels of oil per day and 11.5 million cubic feet of gas per day gross will be shut in while we undergo repairs, which are expected to take about 90 days. In the deepwater Gulf of Mexico, we advanced the development on 3 subsea tiebacks, Wide Berth, Mandy and Bushwood. Wide Berth came onstream last week, producing at gross daily rates of 35 million cubic feet of gas per day and the 3,200 barrels of condensate per day. We continue to clean up with 4 more [ph] expected in a couple of weeks and 50 million cubic feet of gas per day and 4,000 barrels of condensate per day. Development continues at Lucius with spar and topsides construction in progress, a successful appraisal well of Heidelberg extended the oil accumulation of approximately 1,500 acres. A pre-FEED study has been commissioned to determine the development plans. We're currently participating in exploration test at Spartacus in the Lucius, Hadrian play fairway at Walker Ridge, Block 793. We're also waiting on the release of a rig and commence drilling of our Parmer prospect, a subsalt middle Miocene oil prospect that is expected to spud later this quarter. In our Gulf Coast Onshore region, we drilled 7 wells during the quarter with a 100% success rate. This includes a horizontal well in Grindes County [ph] where we're testing Woodbine sands, a 16-stage frac simulation job over a 4,100-foot lateral is scheduled to commence this month. We also TD-ed our spar sale prospect at St. Mary Parish. This is a deep lower Miocene exploration test that we're scheduling for completion in the third quarter to coincide with upgrades under way to Atchafalaya Bay infrastructure. In Canada, the transition to oil- and liquids-rich drilling is fully under way. Sequentially, quarterly oil production is up 5%, and gas volumes increased 22% -- gas liquid volumes increased 22%. We averaged 7 rigs during the quarter, drilling 58 wells with approximately 60% of these targeting oil reservoirs and 1/3 targeting rich gas. The remainder were service wells. Among the region's highlights were the reactivation of Kaybob, a Duke well which tested 1,800 barrels of oil equivalent per day and is currently producing at 1,200 barrels of liquids per day and 2.6 million cubic feet of gas per day. This is the fifth-highest liquid-producing well in Western Canada and is Apache's highest liquid producer in the region. In our House Mountain focus area, a Beaverhill lake test, came in at 700 barrels per day. We also drilled 10 horizontal wells as part of our House Mountain waterflood project, completing the well's multistage asset fracs. Initial results are encouraging with IPs up to 1,100 barrels per day and 9 day rigs averaging 510 barrels per day during flowback. During the second quarter, the region is focusing on Midale and Brownfield oil drilling programs in Southern Alberta and Saskatchewan. In summary, our momentum continues. We had several one-off production disruptions during the quarter, 6,000 barrels per day in the North Sea, 1,500 barrels in Central due to plant turnarounds and 4,000 barrels per day off in Australia due to cyclones. Otherwise, we could have reported more than 780,000 barrels of oil equivalent per day. Apache has a variety of opportunities across its diverse portfolio. In Onshore U.S. alone, we are ramping up our rig count from 32 in January to 52 today and to 60 by year end. Our accelerated activity will translate into visible future production and ultimately more value for our shareholders. We have scheduled a 2012 Analyst Day for June 14 in Houston and plan to highlight our North American resource plays in greater detail. That concludes the operational highlights, and I'll now be happy to turn it over to Tom Chambers.

Thanks, Rod. Good afternoon, everyone. As you've seen by now, we reported earnings of just under $780 million and $2 per diluted share. These numbers tend to mask our underlying financial performance, which continues to provide a platform for long-term profitable growth across our region. I'd like to emphasize what was mentioned previously both by Rod and Steve, in that we continue to grow our business, achieving record levels of production this quarter averaging 769,000 barrels of oil equivalent a day. Coupled with record oil prices, our revenues were the best ever at just under $4.5 billion for the quarter with oil revenues costing $3.5 billion, accounting for 79% of the total. More importantly, these factors resulted in continued strong cash flow with cash from operations before working capital items of $2.6 billion, up 18% from the prior year quarter and in line with last quarter. Our continued ability to generate significant amounts of cash flow from our asset base has enabled us to fund our robust E&D capital program across the globe. And getting after our capital program is critical in realizing the opportunities we have gained through our recent acquisition activity. We've been able to sustain this cash flow despite increasing pressure on North American gas prices, particularly in Canada. As in past quarters, our balanced portfolio has allowed us to benefit substantially from our oil position and the fact that oil currently sells for about 43x the price of North American natural gas. In addition, our international gas portfolio has also provided balance, helping to mitigate a 22% decline in North American natural gas prices from the year-ago period. First quarter 2012 international gas realizations were 17% higher than a year ago and 7% higher than the last quarter, driven by our new sales contracts in both Australia and Argentina. Our acquisition of Mobil North Sea Limited at the end of last year also bolstered our international gas position by adding 65 million cubic feet a day at prices near $8. Our product mix with oil-related growth has helped preserve our financial strength despite significantly low natural gas prices here in North America. Natural gas prices are at levels not seen in over a decade and are straining many producers that are highly leveraged to this commodity. Our Canadian region is the most GAAP-leveraged region in our portfolio, and current period earnings reflect this. First quarter earnings were impacted by a $390 million noncash after-tax write-down for our Canadian oil and gas property balance. Just to reiterate what most of you are familiar with, full cost accounting requires us to calculate the 10% discounted after-tax value of our proved reserves using period-end comps, a 12-month average for commodity prices in effect at the first day of the month. If the discounted value is less than our net book value in a given country, the excess is written off. Adjusting for this noncash write-off and foreign exchange impacts, earnings were $3 per share, up $0.10 from the prior year period and $0.06 sequentially. Higher cash margins of $47.94 per barrel of oil equivalent underpinned our healthy earnings and cash flow. Cash margins were up 9% and 6% versus the year-ago period and the sequential quarter. Our consistent focus on margins and cost trends continues to pay off. Total cash cost, excluding taxes other than income, averaged $13.19 of BOE, in line with our $13 to $13.50 target range for the year. A detailed calculation of our margins, adjusted earnings and cash from operations can be found in the financial supplement located on the website. Turning to the balance sheet. Our ability to consistently generate record cash flows has provided the opportunity for us to meet our planned capital expenditures and continue reaching into the acquisition market. In February of this year, we closed on the 49% share of Burrup Holdings ammonia fertilizer plant for $439 million, which allows us to realize additional price upside on one of our largest Australian gas contracts. And just this week, we closed on the $3.1 billion Cordillera Energy Partners acquisition in the liquids-rich fairway of the Anadarko Basin. To fund these transactions and refinance some maturing notes, we successfully issued $3 billion of new debt in early April, 5-, 10- and long 30-year tranches at very attractive rates. Our balance sheet remains strong with almost $3 billion of available liquidity at the end of March and a debt to cap at only 21%. A key point I need to highlight for the first quarter is our effective tax rate of 49%. Higher than our typical 42% to 44% rate that you've seen. This rate was impacted by the Canadian adjustment mentioned earlier, as well as the higher taxed foreign earnings, contributing more of our overall net income during the quarter. Absent the Canadian adjustment, our effective tax rate would have been a more typical 43%. Similarly, these adjustments impacted our percentage of deferred taxes in the quarter. However, we would expect the deferred rate to move towards the 20% to 25% range for the year. To wrap up, despite the lowest North American gas prices in a decade, Apache achieved its highest quarterly revenue ever. Our fundamentals are strong, and we continue to build a great deal of momentum with each passing quarter. With rising production, strong cash flow, a continued focus on delivering strong margin and an inventory of cost mix greater than any time in our history, we are poised to deliver continued growth and value for our shareholders. And with that, I'd like to turn the call back over to Patrick.

We will now open the call to questions. Operator?

[Operator Instructions] Your first question comes from the line of Arun Jayaram with Credit Suisse. Arun Jayaram - Crédit Suisse AG, Research Division: Yes, I wanted to talk firstly, just trying to set the baseline where guidance is set on the production side. I know you had some asset sales late in the year that maybe impacted Q1 in terms of growth. But I just wanted to better understand what the baseline of the 7% to 13% growth is based on.

It's the beginning of the year trend [ph] sale basically. So I think you heard it pretty much throughout the presentation. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. So we're basically just taking your 2011 growth, backing off the...

About 11,000 barrels of oil, yes. Arun Jayaram - Crédit Suisse AG, Research Division: Okay, okay. That's fair. And Steve, I just wanted to see if you could talk about your confidence perhaps in the middle part of the range. You are starting off a little bit of a lower starting point. Just give us a sense of your confidence to reach perhaps the middle point of that range.

Well, let me put it this way. I feel very comfortable we're going to be ahead at the low end of that range. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. And what do you think would you have to see to get to that middle part of the range in terms of your overall portfolio?

Well, the results that we're going to have in the second quarter are going to be important, obviously. As you move out, the wells you drill in the first 2 quarters are really what sets the stage for your overall production growth. So I'm hopeful we show some added growth in the second quarter and certainly in the first part of the third quarter. We've got a very active drilling program going on right now, most active we've been in some time in North America. Arun Jayaram - Crédit Suisse AG, Research Division: Fair enough. One quick question in terms of Egypt. The gas price, I just wanted to get a little bit of color around the decline of the gas prices. I do know next year contractually, the gas price goes down just because of an expiration of a contract. But I just wondered if you can talk about that quarterly swing and the dips in gas prices.

This quarter, we had an adjustment in the gas price. There was some gas that was booked at that old gas price that wasn't that. So you saw a reduction in the gas price to make up for that error last quarter. It was a onetime quarter deal.

Our next question comes from the line of Doug Leggate with Bank of America.

If I could try a quick follow-up on the Gulf question. Steve, when you say year-over-year, you've obviously had the Beryl acquisition and the Cordillera acquisition. So is the growth target organic growth target or total growth target?

It's a total growth target.

Okay. I just wanted to clarify that. Getting into the details a little bit, can we talk about the outlook for Australia this year? Because obviously, with Coniston scheduled to come onstream, I guess, in a year or so time, there's still I guess some debate over what you're going to do with the FPSO down there. So could you give us an idea as to what the expected downtime will be.

Yes, Rod?

Well, we have a combined Coniston, Ningaloo Vision, which is the name of the FPSO rectification project, which is sort of working both a subsea development in tandem with the repairs and modification. These are making them both. So the -- excuse me, [indiscernible] significant servicing work in early part of 2013. I forget the exact amount of days or weeks that it will be out of service before returning to the field later that year to be able to commence production for the combined Coniston and Van Gogh. I'm sure Patrick can get back with you with that number after the call.

Okay. So the downtime is next year, not 2012?

That's correct.

Okay. Second one for me, Steve, again, just I want to get back to you just again. Unfortunately, it still comes up as an issue, an overhang in terms of the uncertainty over there. One issue I wanted to get some clarity on is the risk of devaluation of the Egyptian currency. How does that affect your business? And I'll leave it at that.

Well, Rod might wanted to jump in there too. In terms of -- we get paid in U.S. dollars. In fact, we export the biggest bulk of our crude production, and that's based on dollars. And the gas sales to Egypt you see are based on U.S. dollar equivalent. So we really shouldn't have any impact based on the dollar side other than maybe a little higher op costs just because they're paid in Egyptian pounds. Egyptian workers are paid in Egyptian pounds.

Your next question comes from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: Focusing on sort of the weakness we've seen on NGL pricing, especially sort of in the Mid-Con region. I believe you've got like a pricing contract that's coming up pretty soon that's due on the technical side. Just sort of how you are thinking about it, maybe various options that you're considering to maybe address what's going on in the NGL pricing.

Well, actually, there's an awful lot of work going on in the industry around that in terms of pipelines, and we're not excluded from that concept. And this is a little longer-term view of life. And it's quarter-to-quarter, but a little bit like we're facing in the Permian Basin. With the resource potential both in the Anadarko Basin and the Permian Basin, the easiest thing to pick is infrastructure, frankly. I mean, it's an industry we're facing that in the Permian, and it's -- those things are going to get built. It might be a quarter late, and everybody wants to project in their numbers. And I don't have any specifics associated with it. I'm just talking a little bit like Crosstex and our step there. In all truthfulness, I don't worry about infrastructure if the wells are good enough. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. If I just shift over to the Permian. Of the 31 rigs you got at the moment, you mentioned 6, right now, are focused on horizontal. I'm trying to get a sense of, around the end of the year, what you would envision that split looking like in terms of horizontal versus vertical.

Well, it's an interesting situation in the Permian. Actually, it's unlike what's happening in the Anadarko Basin. We've got 22 rigs running in the Anadarko Basin. 21 of them are horizontal. In the Permian, that's a much lower number than the industry. In 2010, the number of horizontal wells in the Permian Basin was less than 10%. In 2011, it was a little bit more than that, which you're going to see in the Permian Basin. The same thing is happening in the Anadarko Basin, and the majority of them are going to be horizontal as we get into the future. Right now, I think we're projecting something like 700 wells, of which about 100 of them will be horizontal this year. A little over 100 of them will be horizontal.

And that number is actually weighted heavily on the Deadwood side because over 300 of those wells that are in Deadwood this year, and those are almost all vertical wells, structural reservoir, targets deeper.

And we've got a couple of Cline horizontal wells in there, and we will drill more of Cline horizontal wells in the future. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And just a final question for me. On New Zealand, I believe the first of the 4 wells that you all had planned there was going to spud during the second quarter. Is that still the case?

Yes, it's either the second quarter or the first part of the third quarter. We just -- Rod and I just reviewed that.

Your next question comes from the line of Michael Hall with Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Just curious, as you kind of step back and kind of look at Canada and the opportunity there, kind of in unconventional liquids in particular, I guess how would you characterize that and its lifecycle relative to the U.S. And sorry if I missed it, but did you identify kind of how many, let's say, horizontal unconventional liquids targets you have up there this quarter?

Well, the first question, I will tell you, it's in infancy. What some of the things we're doing on our acreage in the Provost in that area, actually, we've got a huge acreage position there that we're just now beginning to exploit. And that's shallow oil. That's 3,500 to 4,000 feet. And actually, we've had very good success there. Some of the other stuff that you -- the Cadomin and that kind of stuff over to the West, that's a little further along. In fact, what happens in Canada is it's late in coming. I mean, I'll be real honest with you. If you look what happened to gas prices. Everybody was a gas player in Canada until we saw what's happened over the last 18 months on gas prices. So we're not the only ones making that switch. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Sure. Okay. And then just on, the interruptions that we're seeing during the quarter, if I heard that right, I think about 10,000 barrels a day offline. Did those come fully back on in the second quarter?

Well, the ESP work, part of it will be -- we had the turnaround at -- I think it's Bravo on Forties. The ESPs, we've got a rig that we're going to try to pull out there and do some recompletions and pull those pumps on the ESPs. Those may not all be done this year -- I mean, this quarter. But we also have a couple of other good things happening. That Beryl well that Rod mentioned is maybe the best well drilled in Beryl in the last 20 years. And I'd say that, we haven't gotten the test on it yet. So the best thing about it is we haven't tested it yet. It looks fantastic on the logs. I mean, it's virgin pressure. It could be the best well in the Beryl field in the last 20 years.

This is Roger. Then there was 1,500 barrels a day in the Central region, which from a plant downtime, assuming another plant doesn't go down, that would be back online. And then typically, it isn't cyclone season.

We're done with the cyclone season now. We're out of it as of this weekend.

So that's 4,000 barrels a day. So most of it ought to be back online.

Your next question comes from the line of David Tameron with Wells Fargo.

I have to ask, Egypt, can you just give us an update on anything since your last update as far as progress there and the new government and kind of where we stand on that?

Yes, and then again, Rod probably has some comments, too. I will -- Rod and I were in Egypt about 1.5 months ago. I think what you...

Because of the very large concession, because we have a sizable resource. Likewise, the 8 recompletions I referenced and the 5 new drills, those will be focused, for the first time our drilling will be focused in the oil window portion in areas that were very similar and adjacent to like VF and other companies' activities that have had press releases. And we're very encouraged by that outcome. They're on our core concession areas. We had some of our principal productions in the Neuquén Basin, and it's -- we'll have probably more to say about that on our June 14 meeting.

Yes, I think it's safe to say we've gotten some cores. We've done some recompletions down in the oil window, which gives us very good encouragement to drill at least 5 or 6 horizontal wells in the Vaca Muerta shale oil.

That shale is much shallower in those areas compared to the 2 concessions I referenced.

Excellent. Excellent, I appreciate that color, and very quickly on the North Sea, looks like you guys -- the activity's paying off there. How sustainable do you see the rates there for this year that we're seeing out of the North Sea for you?

Well, I think it's early times. I will tell you, the Forties will, we will get that back, and that will be pretty steady. The good thing about the well that we just drilled is we really anticipate having more resource potential there than we thought we did going into it, frankly. I mean, in all honesty, this well found pay but it found much more pay than we thought it would. So it gives us added hope that, that resource potential there is bigger than what we had evaluated.

Your next question comes from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Your U.S. gas volumes quarter-to-quarter down about 48 million a day. Is that because of the divestitures?

Well, you bet. It was actually the divestitures were a little more than that. So that...

50-plus.

I think it was almost 50 million a day. So you're looking at numbers that are comparable to last year. Pearce W. Hammond - Simmons & Company International, Research Division: And Steve, have you seen your gas volumes start to level off in the U.S. or actually decline? Or are they still growing?

Well, if you look at whether it's us or anybody else, when we talk about all of these liquid-rich plays, the Marmaton well that Rod mentioned is making over 800 barrels of oil a day. It's also making 10.5 million cubic feet of gas per day. And we've got 90% of that well. We've got a -- the Marmaton is going to be a good play. We've got -- it's not nearly as continuous as all those plays, but we've got, we've picked up a very big acreage provision from Cordillera in that play, and that's the second or third well drilled in the Marmaton, only second or third well drilled, so, so far, that's -- but you're going to see a lot of gas besides the liquid side of it.

If I might comment, we've got 60 rigs running in America now, and 58 are targeting liquids-rich and oil. So to the extent -- we're a lot like everybody else, dry gas, we're just not drilling for. The other thing that might have gotten lost in the numbers is our gas production was up 3% sequentially. Well, it's because even though we're down in North America by about 40 million a day with the property sales, we're up 110 million abroad, which is, as Steve pointed out, we've got $4.02 during the quarter. It rose $0.27 from the prior quarter. Internationally, it's the first quarter where we're seeing our international prices higher than our North American prices. So our revenues are climbing internationally on the gas side. Pearce W. Hammond - Simmons & Company International, Research Division: Great point. Great point. And then just one follow-up. If you could provide an update on Kenya.

Kenya should spud in the latter part of July. We've secured a rig. In fact, Rod and I reviewed that a couple of days ago. We should spud that well in the latter part of July.

Your next question comes from the line of Matthew Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick follow-up questions for me. Along the same vein on the U.S. gas production, could you provide any additional color on potentially how that could trend over the year if you're expecting kind of a steady increase or at some point, we'll see that leveling out? And then within Canada, as there has been historically a little bit more gas-focused, should we be thinking about those volumes declining and any potential risk on shut-ins?

We just quickly looked at our outlook. I would suspect if our outlook is correct, our gas from the U.S. is pretty well flat, maybe a little up. In terms of -- what was -- the other one was about Canada? Yes, shutting in production is if it covers operating costs, there's no economic reality to it. And I don't anticipate us in any of our gas deals to get to the point where we shut in gas because the operating costs are higher than the price we're receiving. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just to follow-up on that, I guess within Canada, and this might be an unfair assumption, but I'm assuming there's a little bit less liquids-rich drilling activity at the moment from you guys. Should we think directionally your Canadian volumes should start to decline at some point this year on the gas side?

Well, you'd presume that, that would be the case with virtually no wells targeting dry gas up there. I wanted to clarify one thing on Steve's point. When he said flat, he's really, I think, thinking from this day forward with Cordillera built in because we're, of course, picking up quite a bit of gas there. So we ought to be able to have U.S. volumes flat to rising somewhat through the balance of the year.

Your next question comes from the line of Brian Singer with Goldman Sachs.

On the LNG side, we've seen a number of LNG contracts signed for U.S. LNG here year-to-date. Can you give us an update on how you see the strength of the market, particularly the Asian market? And then given your advantageous geographic position at Kitimat to serve the Asian market, can you refresh us on what the key constraints are to an announcement on Kitimat? Is it the FID that gives you confidence in the greenfield costs or some other reason?

Well, we -- and Rod again could do this a lot more in detail. But we are pretty much done with the FEED. I mean, I can't tell you enough that the real bottom line for Kitimat or any of these projects, what's happening in the U.S. is an anomaly. It's not a greenfield development. So what you're looking at, whether it's us or Shell, I read this morning that Imperial's thinking about getting in the business, all of those contracts are going to have to be oil-based contracts. And we truthfully are in the throes of negotiations for a very, very -- a tenant that could underpin that development. But we're not there until we're there. So we're continuing to negotiate. We're also continuing to declare right-of-way for the pipeline, and we're working towards the construction of the LNG facility. It's not a cost, as much as it is -- of course, they're, like anything, cost and price, are synonymous. I mean, it's -- but we haven't seen great increases on the cost side as we move through FEED.

Okay. And my follow-up is, can you just refresh us post-Cordillera acquisition, what we should expect to see your corporate CapEx run rate to be as we go through the rest of the year?

Yes, we're going to stay within our cash flow. I don't know where our capital budget was for this first -- I mean, I know, but round numbers...

9.5 is what we said.

Yes, and it's 9.5 to 10, honestly. We're going to have cash flow, usable cash or spendable cash around $10 billion for the year. And that's -- whatever we have is going to go on the ground.

Okay. But no other changes beyond, I think, a slight point you made on Argentina?

No, no, I mean, we're going -- we increased it $50 million to drill those Vaca Muerta shale wells. So it's not a huge bump.

The way we look at that, you heard about the increases in the rig count in the Mid-Continent or Central region, Anadarko Basin, also in the Permian. And if cash flow holds up, then we'll just keep that many rigs or more running. And if cash -- if prices come down, then we might cut that back later. So that's kind of how we jigger it to live within cash flow.

Your next question comes from the line of Leon (sic) [Leo] Mariani with RBC.

Just looking for a little bit more clarity there on Kitimat. Do you guys still think you'll make a decision to potentially build over the project by the middle of the year?

I can't -- I don't think I can be more -- we're going to make a decision when we have all of the Is dotted and Ts crossed, and the most important I dotted and the T crossed is to have an MOU that is good enough in order to -- on the sales side, in order to take this project forward in an economic basis. And if that comes in the middle of the year, it will be middle of the year. If it comes in the third quarter, it will be in the third quarter.

All right. Can you guys comment on the big onetime D&A expense this quarter?

Again, Leo?

You had a big onetime D&A expense this quarter like $520 million. Can you...

Yes, that was the Canadian write-off.

Okay. Got you...

That was total in cash.

Got you. And can we get some more color on the discovery you made in Australia you talked about earlier?

Well, Tallaganda is a project that's about 100 kilometers southwest of our DeSoto discovery from 2011. As I indicated in my remarks, it covers about 190, 160 feet per day [ph]. But the well is operated by BHP. We really have to defer our comments to the operator. Right now, we're evaluating the results of the well to see the forward path on future development. But we have to follow BHP's lead.

Got you. And do you think that's oil or gas?

Well, I think I'd defer to the operator. I hope based on whatever press releases they've had out there, which is I don't think they've had much the way it's...

Your next question comes from the line of John Malone with Global Hunter Securities.

On Australia, it looks like CapEx was down a bit quarter-on-quarter. Is that just the general lumpiness of projects? [indiscernible] a trend there? And also on that, when do you start to see LNG spending really start to kick in?

Well, yes, quarter-on-quarter, they may be just a little bit behind, but I fully expect them to achieve their targeted CapEx amount for the year. We've reviewed this on a monthly basis on our call just 2 days ago. As far as the LNG, we have some of the initial LNG-related. Some expenses are beginning late last year and throughout 2012. But the really big spike in those expenses will come in late 2013 and 2014 when the subsea is opened. It gets in place in fabrication and the central processing plant form and the gas plant begin in earnest.

Okay. And then just going over to Egypt for a second, I think you mentioned it before, but what was the gross production would have been without the PSE effects?

Growth production was up 1% on a BOE basis, and our gas, oil prices were up 16%, which is basically on a PSE basis, we get less product in order to get the same cash back. So our oil was down about 4,500 barrels a day on a net basis. But it's -- on an overall gross uptick basis, it was up. So you'll see that turn around again next quarter.

My simple way of describing that is if you got $100 of costs to recover and oil is selling at $100, then you've got 1 barrel. And if you have $50 oil, then you get 2 barrels. So when prices go up, it works the opposite of that.

Okay. And then just on Egypt, you were talking about the politics, just I know you can't extrapolate, as to what you think Egyptian politics are going to do, but how do you think it affects your gas prices if subsidies were eliminated or curtailed?

Well, they've been talking about curtailing subsidies for at least a decade. I guess the good news in that is they actually made it a very transparent part of their budget about 7 or 8 years ago that we actually see the big elephant that is in the room. The subsidies or energy budget gas and oil refined products is probably going to run 115 billion Egyptian pounds in the coming budget year from what I read, which is significantly a lot lower than it was a few years ago, which is about 70 something-billion pounds, about $10 billion. I don't think that the subsidy issue is going to be resolved anytime soon. I mean, we may see some effects on the refined products like gasoline. But to give you an idea of just how extreme that subsidy is, 92 octane gasoline, I just read this morning, the subsidy sells at the equivalent price of $1.09 U.S. per gallon. The people who burn 92 octane are people with nice cars, not poor people or farmers with tractors and use lower octane fuels. So that's a pretty healthy subsidy for people who could afford to pay a regular price. I think the near term, what we're going to be faced with, at least for the next 5 years, I would expect to see the same contractual gas price on our gas sales agreements, which is tied $2.65 per million BTU. Unfortunately, we have very rich gas that we get more than that, $3 to $4 per Mcf basis, and oil price, of course we receive the world price based on our export volumes on the Brent market.

At this time, there are no further questions. Presenters, do you have any closing remarks?

Yes, Sarah, I do. Thank you for participating in our first quarter earnings call. I do want to acknowledge that we've been just made aware of some technical difficulties with the sound. So I want to apologize to those who were listening or will be listening to the playback. We will have the playback on our website within 1 hour. And thank you again for your participation.

This concludes today's conference call. You may now disconnect.