APA Corporation (APA) Q2 2012 Earnings Report, Transcript and Summary

Patrick Cassidy - Director of Investor Relations G. Steven Farris - Chairman, Chief Executive Officer and Member of Executive Committee Rodney J. Eichler - President and Chief Operating Officer Thomas P. Chambers - Chief Financial Officer and Executive Vice President Janine J. McArdle - Senior Vice President of Gas Monetization

Arun Jayaram - Crédit Suisse AG, Research Division John Freeman - Raymond James & Associates, Inc., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Pearce W. Hammond - Simmons & Company International, Research Division John Malone - Global Hunter Securities, LLC, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Good afternoon. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation Second Quarter 2012 Earnings Release Conference Call. [Operator Instructions] After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] I would now like to turn the conference over to Mr. Patrick Cassidy, Director of Investor Relations. Sir, you may begin.

Thank you, Regina. Good afternoon, everyone, and thank you for joining us for Apache Corporation's Second Quarter 2012 Earnings Conference Call. This morning, we reported earnings of $337 million or $0.86 per diluted share. Adjusted earnings, which excludes certain items that impact the comparability of results, totaled $821 million or $2.07 per diluted share. Cash flow from operations totaled $2.4 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 discussions 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.

Thank you, Patrick, and good afternoon, everyone, and thank you for joining us today. I'm sure all of you have seen that in our recent Investor Day, we outlined our extensive oil and liquids drilling inventory in the onshore U.S. We have over 67,000 future drilling locations that have been technically assessed, and we also have 9 billion barrels of oil equivalent net unbooked inventory that is available to drive our growth in the years to come. And this inventory is already beginning to deliver meaningful results in our onshore. During the second quarter, our Permian and Central regions grew net production at annualized base of 23% and 18%, respectively, and this was before the contribution of Cordillera assets that we acquired at the end of April. Obviously, not every quarter's going to be as good, but we're firmly on track to deliver the double-digit growth in these regions for the years to come, as we outlined in our Investor Day. Moreover, if you count the land drilling rigs operating in the United States from the Rockies to East Coast, Apache has 62 rigs running, which is the second most active operator out of all the independents and majors, and that's only behind Chesapeake, which really has a different focus and business model. I might point out that not a single 1 of the 62 rigs is drilling a gas target. We said we were going to step up our U.S. drilling activity to exploit our enlarged portfolio, and we're doing just that. Our total reported production in the second quarter was reduced by a 16 -- which is the difference between a hit and a miss on our production growth. We had offline about 16,000 barrels of oil equivalent a day. This includes 4,800 barrels a day due to unscheduled downtime at our third-party operated SemCAMS plant in Kaybob in Canada. We had 2,000 barrels of oil a day down in the Gulf Coast Onshore due to a third-party pipeline outage in the Lake Paige Field, 3,200 barrels of downtime due to unscheduled facility repairs at Grand Isle 43, which is the complex in the Gulf of Mexico, and 6,000 barrels of oil equivalent a day out of service due to ESP failures at the Forties Field. Most of the 16,000 barrels a day is already back on stream or is expected to be back before the end of the year. I know downtime happens it's part of our business. The important thing is that we have a robust portfolio. So it really doesn't impact us over the longer term with the performance of the company. We remain on track to deliver our production growth guidance in 2012 without any need to significantly increase our capital program for the year. We have a very active exploration program through the rest of the year, and we expect to further accelerate our exploration activities in next year and beyond. I'm sure most of you have read in the Gulf of Mexico, we have expanded our exploration block portfolio by 40%. We were the most active bidder in the Central Gulf of Mexico Lease Sale held in June. We picked up 90 blocks, 61 on the shelf and 29 in the deepwater. We're excited about the prospects we've identified on the blocks that we've won and expect to ramp up our exploration activity in the Gulf of Mexico significantly over the coming quarters. We've already secured one new build semisubmersible deepwater rig, which will be dedicated, it is separate and it should be delivered in the middle of 2013. In Kenya, our offshore Mbawa well prospect is expected to spud in about 10 days. We should have results by our earnings call in November. We're -- this month, we're deploying one rig in the Mississippian Lime where we've built [ph] 580,000 net acres. We're also deploying one rig in the Williston Basin, where we have secured a new exploration position of about 300,000 acres. Both of these we're expected to drill 4 to 6 wells at each one of these 2 exploration plays over the next 6 months. We also plan to spud our first Alaska Cook Inlet well in October. So we're very enthusiastic about Apache's enlarged portfolio, what we're delivering and what's ahead of us. We've already become one of the most active U.S. onshore drillers among our peers in the majors, and we're pursuing an exciting portfolio of global exploration opportunities. We're doing this all while maintaining our rate of return focus and the financial discipline that are defining characteristics of Apache. I'd like to turn the call over to Rod Eichler.

Thank you, Steve. I'll begin with onshore North America as it was the focus of our recent Investor Day conference and is the area where we are currently most active. In the Permian, we reached a company milestone in the second quarter with production surpassing 100,000 barrels of oil equivalent per day marker for the full 3-month period. During the second quarter of 2012, net production was up 5.3% over the previous quarter at 104,500 barrels of oil equivalent per day, of which 72% was liquid and more than 3/4 of that was crude oil. Also included in total volumes are nearly 2,000 barrels of oil equivalent per day, of positive prior period adjustments, the majority of which are attributed to non-operated fields. Drilling at Deadwood in the Midland Basin and the Glasscock County continues to be a large contributor to growth, with horizontal drilling in the Wolfcamp emerging as a new development area. For the quarter, Permian averaged 32 drilling rigs, up 4 from the previous quarter, on the base properties, adding 187 wells, of which 167 were vertical and 20 were horizontal. We are currently running 36 rigs. Other than 2 weeks of working inventory, we have almost no backlog of stimulation jobs. In the Deadwood vertical play, we are targeting Wolfwood, that is the Wolfwood through the Wolfcamp reservoirs, and Fusselman vertical wells. We've had several notable test results with wells flowing in excess of 300 to 400 barrels of oil per day for intervals covering the Wolfwood reservoirs. We also have a number of locations where we'll initially complete only the deeper Fusselman formation and recompleted later at Wolfwood formations at hole [ph]. Our Amberjack well is a Fusselman-only completion and tested at a rate of 285 barrels of oil per day plus 180 Mcf per day. These add volumes at a very low cost, boosting the well's EUR and rate of return. We estimate that 1 out of 5 Deadwood wells can produce from the Fusselman. We're currently drilling primarily in 40-acre spacing at Deadwood, testing some 20 for down-spacing. This program is expected to remain active through 2012, drilling more than 300 wells in the second half of the year. In our Wolfcamp Shale play in Irion County, our 4 Wolfcamp horizontals have produced more than 190,000 barrels of oil equivalent since March 19. These are outstanding wells, all upper Wolfcamp producers, nothing in the liminal [ph] zones. This appears to be a very thick, very brittle shale and breaks nicely with fracture stimulation. We currently have 3 rigs running in the play and have already drilled 5 additional wells, which are currently being completed or expected to be completed soon. Turning now to our Central region in Oklahoma and the Texas Panhandle. Second quarter production averaged 55,200 barrels of oil equivalent per day, a 47% increase over the preceding period. Nearly 30% of that production was liquids as the region continues its transition to oil and liquid-rich plays. A total of 28 wells were completed in the period, with 12 in the Granite Wash formation, averaging a 30-day IP rate of 1,625 barrels of oil equivalent per day, of which 54% is liquids. We also completed 10 Tonkawa wells with an average 30-day IP rate of 310 barrels of oil equivalent per day, and these are 80% liquid producers. I continue to be impressed with our Bivins Ranch development in the Texas Panhandle. Apache holds a 74% working interest in 124,000 contiguous acres at Oldham, Hartley and Potter counties. We have completed 8 out of our first 9 Canyon Wash tests. 6 wells averaged more than 400 barrels of oil per day for the first 30 days. Our 2 newest wells, completed in the last couple of weeks, are currently testing just under 700 barrels and roughly 1,000 barrels of oil per day. We have just completed installation of a 10-inch pipeline and gathering system and are now selling 3,300 barrels of oil equivalent per day from Bivins Ranch. Look for even more results in the future as a second rig is scheduled to arrive in Bivins Ranch in mid-September. Assimilation of the Cordillera operations is fully underway. We started the period with 10 rigs, averaged 19 for the quarter and exited with 22, and we're currently at 24. Before moving to the Gulf of Mexico, I want to comment briefly about onshore cost and takeaway capacity. We're seeing some softening for service cost across the board. Historically, we've seen cost come down on a lower commodity price environment. Our activity level and growth plans provide us with the flexibility to adjust our operations as circumstances change. Our drilling program is based on our rate of return, not on commodity prices. If trends continue, we expect to maintain or even increase our activity into these market conditions. We also have not had any material issues involving NGLs, but as -- Apache has been very proactive in securing market-sourced liquids where possible. For example, we've headed into a joint venture to build a new gas processing plant and to rail NGLs to the Gulf Coast. We have continued to work with other Permian Basin midstream players that control Apache NGLs to secure unconventional means to avoid product curtailments due to NGL constraints. Turning to the Gulf of Mexico shelf. We TD'd 7 wells during the quarter and operated 5 rigs with 83% success rate. Our production for the second quarter of 98,000 barrels of oil equivalent per day was down 7% over the previous quarter. Downtime at the Grand Isle 43 complex for repairs and maintenance impacted our production during the period. Third-party pipeline and host facility downtime during Tropical Storm Debbie also deferred volumes. These shut-ins were partially offset by new pipeline installations at Vermillion 380 and Ship Shoal 91 and new wells at both Eugene Island 330 and Main Pass 308. Grand Isle 43AA facilities began ramping back up last week and is expected to be at the full rate over 7,500 barrels of oil equivalent per day net later this month. Notable drilling activities during the quarter, including a well at Main Pass 308, which IP'd at more than 900 barrels of oil per day. We have 4 additional locations drilled there. We also successfully drilled 2 wells at the Main Pass 311 and 314 area, finding 120 feet and 39 [ph] feet of pay, respectively, and are in process of completing there. On the regulatory front, 17 of 61 blocks where we were the high bidder of the June lease sale had been awarded so far. The permitting environment continues to be improve, both for drilling and exploration plans. In the deepwater Gulf of Mexico, production increased 13% from the previous quarter to 15,700 barrels of oil equivalent per day. The Mandy subsea tie-back project in Mississippi Canyon 199 came online, producing 5,000 barrels of oil per day and 3.5 million cubic feet of gas per day gross. We hold a 50% working interest in 2 wells in this field and a 15% override in a third. Our Geauxpher well, Garden Banks 462 continues to produce, holding up the start of our Bushwood development in the adjacent block, Garden Banks 463. We are ready to commence production once the Geauxpher well is completed, Bushwood is expected to IP at about 50 million cubic feet of gas per day, and we hold a 50% working interest. Development continues at Lucius and Keathley Canyon 875 with spar and topside construction in progress and major service and equipment contracts awarded. We expect development drilling to commence in the second half of the year with initial production still expected by year-end 2014. Our Deepwater team is also very active in the Central Gulf of Mexico lease sale, bidding on 43 blocks, 19 with partners. We were the -- high bidder on 29 blocks, and 3 have been awarded to date. We have identified 20 new prospects on these blocks, 17 of which will be Apache-operated. In our Gulf Coast Onshore region, production in the second quarter was 25,000 barrels of oil equivalent per day, down 11% sequentially due primarily to third-party pipeline issues to Lake Paige Field in Terrebonne Parish, Louisiana. We anticipate Lake Paige being brought back online by mid-August, according to latest reports from the pipeline operator. During the quarter, we ran 3 operated rigs, drilling a total of 18 wells with an 89% success rate. One well to highlight is our Chaplin [ph] Ranch in Oasis County, Texas, which came on at 9 million a day and 1,020 barrels of oil per day. Turning to Canada. The region's drilling program continues to focus on oil and liquids-rich gas plays. The second quarter coincides with traditional spring breakup season, which impacts our drilling activity. So we saw our production declined 3.8% to 123,100 barrels oil equivalent per day as we drilled only 5 wells during the period. Our drilling is ramping back up in the third quarter targeting oil and liquids-rich gas. We plan to drill 20 Viking horizontals and 39 wells in Consort. In Midale, we expect to drill 4 additional horizontals. Moving on to the international areas. In the North Sea, production was up 36% over the prior year quarter as we continued to assimilate the Beryl properties. We are following up on the Beryl Bravo B72 well with the B73. As you may recall, B72 tested in excess of 11,600 barrels of oil per day and 15 [ph] million cubic feet of gas. The B73 accounted 358 feet of net pay TBD in 4 zones, and it is planned to come onstream during the third quarter. Looking forward to new prospects, the Beryl 3D seismic campaign will begin in early August and continue through until mid-October. The Bacchus Field commenced production during the second quarter. This is the first subsea tie-back to the Forties Field. The second horizontal well, Bacchus West, penetrated Jurassic-aged Fulmar reservoir sandstones and logged 889 feet measured depth of net pay of 3 Fulmar sections. Both Bacchus wells are now online flowing at a combined gross rate of nearly 13,000 barrels of oil per day. Following completion operations at Bacchus, the rig will move to appraise the Aviat shallow gas accumulation. Turning now to Egypt. We are operating a record number of rigs, 28, in the Western Desert. During the second quarter, we drilled 68 wells, including 16 exploratory wells, with 13 successes. Second quarter production declined from the preceding period, primarily due to planned shutdowns at our Salam gas plant where preventative maintenance was undertaken on trains 1 and 2, resulting in the 13 days of downtime. Among the drilling highlights were an exploration well on our West Kalabsha Concession at Faghur Basin that tested 1,600 barrels of oil and 730 Mcf of gas per day from the Jurassic Upper Safa. At our Khalda area concessions, we drilled our first Jurassic discovery at Alamein Basin, identifying 5 hydrocarbon-bearing passages in the Upper and Lower Safa. We're currently planning to test this well but it requires high-pressure equipment as it is the deepest well drilled to date by Khalda Petroleum Company. An exploratory well, the Hot 1-x [ph] was drilled in WD 30 development lease at the Abu Gharadiq Basin, testing nearly 3,000 barrels of oil per day. This success high-grades numerous nearby oil-prone prospects. Also in this basin of the WD 30 development lease, Shadow 1X encountered 62 feet of gas and oil pay, testing an initial daily rate of 1,200 barrels of oil and 6.5 million cubic feet of gas per day. In the Khalda Offset Concession, we conducted production tests from the first 2 producer wells in the Utis [ph] field during the quarter, with each producing in excess of 2,000 barrels of oil per day. This is a traditional core KPC property, and we have 12 more wells approved for the field. We are seeing a shift to more complex drilling agent, particularly at Khalda. This includes record-setting drilling depths, new frac records with parts at deeper zones and high pressures at our first horizontal well, which we plan to frac and test in the third quarter. During the quarter, we continued to make progress on a number of commercial issues. This includes the signing of 5 new gas sales agreements at Highford [ph], Utis [ph], Sultan, Alpha and Chelsea, which should allow us for the debottlenecking of gas production in those concessions. And our Hydra [ph] development lease was signed, commercializing this 200-plus Bcf gas and condensate discovery. Hydra [ph] is expected to come on stream by year-end 2013, producing at an expected rate of 11,800 barrels of oil equivalent per day. In Australia, the second quarter net production was 66,000 barrels of oil equivalent per day, down 3% from the first quarter largely due to forecasted declines in major oil producers, Pyrenees and Van Gogh, and seasonal reductions in gas purchases by industrial customers. Van Gogh production averaged 10,700 barrels of oil per day during the period. Uptime has been excellent, and the facility produced continuously throughout the quarter. On July 5, 2012, Apache achieved a milestone when it took over operatorship of the Ningaloo Vision FPSO from the previous contract operator. We purchased this FPSO vessel earlier this year. Looking ahead to the third quarter, production from the new Pyrenees Stickle 8H well commenced on July 14 and added an incremental 11,000 barrels of oil per day or 3,135 barrels of oil per day net to Apache to the total field production. Gas sale volumes in Australia will be reduced in late September when the Yara Pilbara fertilizer plant shuts down for maintenance. It is expected to be offline for approximately 3 weeks. Yara Pilbara normally takes 75 million to 80 million cubic feet of gas per day, Apache's share being 80%. Finally, in Argentina, net production in the second quarter was 50,000 barrels of oil equivalent per day, a 5% increase over the Q1 2012. Our gas price realizations in Argentina continue to be supported by the Gas Plus Program. Our second quarter gas realizations where $2.76 per Mcf. And in June, we sold 97 million cubic feet of gas per day at an average of $4.96 per Mcf under the Gas Plus program. In Tierra del Fuego, the elimination of an existing provincial tax benefit reduced our average oil price realizations in the region by 30%, contributing to a reduction in the overall Argentina oil price realization to $72.69 per barrel. On the exploration front, seismic sequence mapping, petrophysical modeling, core [ph] descriptions and mud log analysis have helped to high-grade recompletion candidates, and identifying sweet spots within the Vaca Muerta as we look to identify horizontal drilling locations. We plan to drill 4 horizontal and 2 vertical exploration wells and to conduct 6 vertical rig completions with 10 fracs in 2012. The first horizontal well was spud within a week and is expected to be completed in September. We are hoping to have more well results to disclose in the first quarter of 2013 Exploration work continues on the Huacalera and Cortadera blocks to identify additional intervals to the Vaca Muerta we're testing at Huacalera X1. In conclusion, across our portfolio, we have no shortage of opportunities and the ramp-up of our drilling program is well underway. Our major prospects are progressing and on schedule. With results of our accelerated drilling activity beginning to take hold, we anticipate most of our 2012 growth to be in the second half of the year. That concludes the operational highlights, and I'll now turn it over to Tom Chambers.

Thanks, Rod, and good afternoon, everyone. As you've read previously in our press release and heard earlier on the call, we are rapidly building a significant inventory of drilling opportunities and have established a robust platform for long-term growth across all of our regions. We achieved solid production level this quarter averaging 774,000 barrels of oil equivalent a day despite some significant third-party challenges. This is the ninth consecutive quarter of production growth, and we exit the quarter with continued upward momentum. For the second quarter, we reported earnings of $337 million or $0.86 per diluted share and adjusted earnings of $821 million or $2.07 per share, and we adjust for certain items that affect the comparability of results such as the noncash property write-down in Canada and foreign currency fluctuations. Our bottom line results were impacted by lower commodity prices, yet we were still able to generate revenues of almost $4 billion. This translates directly into significant cash flow from operations, $2.4 billion this quarter. Year-to-date, our cash flow from operating activities before changes in working capital was 3% higher than the prior year-to-date period. On the quarter, our cash flow from operations was down 10% over the previous quarter, primarily driven by lower oil and gas price realizations, which were down 12% and 8%, respectively. International gas prices helped mitigate the decline in earnings and cash flow, with realizations up slightly from the previous quarter and 29% higher than North American average realizations. For the past 2 quarters, we have realized over $4 per Mcf on our international production, a sharp contrast to the North American prices, which averaged well below $3 per Mcf over the same timeframe without the benefit of hedges. Year-over-year, we produced 100 million cubic feet a day of additional international gas. And in the second quarter, it represented 37% of our worldwide gas production. As economic uncertainties continue to weigh on commodity prices in the global economy, we remain optimistic given our ability to consistently generate cash from operations. Our position is supported by the strength of our portfolio, which has enabled us to benefit substantially from our oil position and the fact that oil currently sells for nearly 30x the price of North American natural gas. Our efforts to expand our North American liquids portfolio was also evident this quarter as we closed the Cordillera acquisition in April for approximately $2.6 billion in cash and approximately 6.3 million common shares. This significantly increased our Central region's liquids production, 60% over the first quarter and added over 300,000 net acres to our prolific Granite Wash play in the surrounding areas. We were also able to secure a significant number of offshore blocks in the deepwater and shelf regions through the Gulf of Mexico offshore lease sale in June. This provides more growth potential in these regions where we received some of our highest liquids prices in America. In fact, over 40% of our North American oil production comes from our Gulf Coast regions, where average crude price realizations currently reflect over a 20% premium to West Texas Intermediate pricing. Our focus on oil and liquids will continue given the general weakness in North American gas markets. As a result, we again had a noncash write-down of our Canadian oil and gas properties. Our Canadian region is the most gas levered of our portfolio, and we recognized a $480 million after-tax write-down of the property balance during the quarter. As a reminder, full cost accounting rules require us to discount our proved reserve value at 10% using prices in effect for the past 12 months. The amount of our recorded book value over this discounted value is written off. This is a noncash event that will continue to impact us until North American gas prices no longer decline compared to the prior year. Excluding the write-down, our margins for the second quarter remain strong. At $39.72 per boe, we're still realizing robust cash margins despite the 12% decline in average price realizations. You can find a detailed calculation of our margins, adjusted earnings and cash from operations in the financial supplement located on our website. For the second quarter, you'll specifically notice an increase in our debt. Our strong balance sheet enabled us to reach into the debt market to fund significant acquisition activity. In April, we issued $3 billion of debt in 3 separate tranches at very attractive rates to fund the cash portion of the Cordillera acquisition and repay $400 million of higher interest rate notes that came due in April. We finished the quarter with a debt-to-cap of 25%, cash on the balance sheet of $360 million, which is $116 million higher than the prior quarter; and available borrowing capacity of nearly $3 billion. So we remain to have a flexible balance sheet. Turning to taxes. The second quarter effective tax rate of 56% reflects the Canadian ceiling test adjustment, as well as higher-taxed foreign earnings. Absent the Canadian write-down and the impact of foreign exchange movements, 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 a deferred rate of 20% to 25% for the year, absent these adjustments. As we head into the third quarter, our income taxes will be impacted by the U.K. government provision to decrease tax relief attributable to decommissioning expenditures on the North Sea oil and gas facilities from 62% to a maximum of 50%. The legislation was enacted in July of 2012. And as a result, we will record a deferred tax charge in the third quarter of 2012 estimated at approximately $40 million. To wrap up, we had another quarter of solid production and cash flow. Apache is not immune to the current commodity price pressures faced by the industry, but we are optimistic about the second half of 2012, given our ability to deliver strong cash margins with a rising inventory of drilling prospects. We are actively increasing our activity across a board -- a broad portfolio of opportunities and are confident our results will reflect continued growth and value to our shareholders over the longer term. And with that, I'll turn the call back over to Patrick.

Thank you, Tom. We will now open the call to questions.

[Operator Instructions] Your first question will come from the line of Arun Jayaram with Crédit Suisse. Arun Jayaram - Crédit Suisse AG, Research Division: I'm wondering, Steve or Rod, if you could give us a little bit of a road map relative to the near-term production picture. The guidance is 6% to 9%. I know that's adjusted for asset sales, but the way I'm thinking about it is you produced about 748,000 barrels last year. If you back out 11,000 from asset sales and then you apply the 6% to 9% range, so that would put you in the 781,000 to 803,000 [ph] kind of range in terms of thousand barrels a day, is that how you're thinking about 2012?

We'd better hit that. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. Okay. And obviously, Steve, you highlighted you had quite a bit of production, 16,000 barrels come online, and you said most of that's come back. I don't know if you could give us a little bit of specificity around when that came back and just so we can kind of fine-tune our third quarter and Q4 numbers.

Yes, Rod -- I'll mention a couple of them, and then Rod will obviously give some more detail. But SemCAMS plant in Calgary went on, in Canada, went on, on July 6. So we should get all of that back. Now that's -- you've got all kinds of things going on in terms of it, but we -- that plant is back on. That was about 70 million a day. It was a big hit. We should have Lake Paige on about the middle of August. Grand Isle -- I mean, West Camp 43 is ramping back up. In fact, it should be back up right as we speak. It started ramping up about the fourth of July, and that was very unexpected downtime. Lake Paige was totally unexpected. We had a confluence of things that hit us all in one quarter, which you usually get over the whole year. In terms of the North Sea, we're doing 2 things. One is we're going in and replacing ESPs or pulling ESPs on the Forties. But we also got, as Rod pointed out, we just had the Bacchus well come on. And also our Beryl well hopefully will come on, Rod, in the middle of this month?

Yes, yes.

And we're expecting great things out of it. So. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. It sounds like you got a lot -- most of that coming back on track this quarter. My follow-up is, obviously you talked quite a bit at the Analyst Meeting about the Permian and the Cline Shale, and the horizontal Wolfcamp, that results looked pretty positive. As you think about next year, I know it's early but I was just wondering how you're thinking about activity in each of those plays and broadly into the Permian into 2013?

Well, we're running 36 rigs in the Permian Basin right now, and honestly, you're going to see -- I mean, it's not a lack of inventory. So you're going to see that ramp up, and I think right now, I think Alfonso's plan had it at 40 rigs next year. That's probably conservative. In terms of the Anadarko Basin, we're running 26 rigs right now. And frankly, that's higher than we had in our outlook for the Investor Day. So we're -- I think in the Investor Day, we showed that the Permian would grow on an annualized rate over a 5-year period of about 13% and the Central region, if you don't include the Cordillera, our 5-year growth would be about 23%. And we're very comfortable with those 2 numbers.

Your next question will come from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: Just a follow-up on the last question again on the downtime. I didn't quite hear the 6,000 that's offline on the Forties. Just a ballpark idea of when that returns.

That Forties production is we have 9 ESPs that are principally off the Beryl -- I'm sorry, off the Forties Bravo platform. Those are being restored in sequence that we've fired up the platform drilling rig here on the late part of the second quarter. So we're swapping in the ESP replacements with new well -- new drilled wells. Whichever has the highest rate of return to us gets the favored treatment. So we're probably seeing those ESPs return in production through the rest of this year and perhaps even in the first quarter, intermixed with normal drilling activity on the same platform. I should note that the ESP run life out there is typically about 680 days, and that gives you an idea that about 2 years ago, most of those ESPs replaced in the last cycle, and so they all start falling about the same time. John Freeman - Raymond James & Associates, Inc., Research Division: That helps. Of the incremental rigs that you added in the Permian going from 31 to 36, the 5 that were added, are they being focused mainly horizontal or can you give me maybe the current mix?

One of them is in Wolfcamp, and then 2 of them are in Deadwood, and I don't know where the other 2 are off the top of my head.

Just a second. I'll look it up for you. John Freeman - Raymond James & Associates, Inc., Research Division: And while you're all looking for that, just the last question I had while you're looking at that. The well in Kenya that I believe was supposed to be spudded at the end of July, has that well been spud?

No. In fact, I think it's going to be spud on August 15.

Your next question will come from...

We currently have 6 horizontal wells operating in the Permian, they're scattered at the moment among the leased properties. So we have 2 rigs operating in the Wolfcamp Shale, which is a new area of expansion for us south of Deadwood, and we see that to be a continuing area of increasing drilling focus in the coming year.

Your next question will come from the line of Doug Leggate with Bank of America.

I'm going to try a couple as well, if I may. I guess on the first question that was asked about production. I wonder if I can just push you a little bit on that because clearly if you get the target, to stay within target this year, it looks at least on our numbers that you'd get on to a fairly big step-up in the second half. Can you give us an idea of what the portfolio is doing currently? And would you be prepared to give us a trajectory through the back end of this year because obviously, we're -- I guess marking this issue [ph] with a bit of line of sight here.

Yes, with respect to direction, we've got half a year and you've got 2 quarters of production. I think it's pretty easy to calculate what it's going to take to get to 6% to 9%. In terms of -- I'm sorry, I didn't catch your other question.

I'm just trying -- where is the portfolio right now, Steve?

Well, we don't -- I've got to tell you it's higher. I will tell you, we don't give month-to-month production. I will tell you it is higher than what our average was, and we went -- each month went up. So July is higher than our average for the first -- the 3 months of the second quarter.

All right. I won't push that one too much. So just one other one from me then. Egypt, it was -- production obviously was kind of flattish despite the decline in the oil price while realizations were -- seemed to have dropped off relative to your kind of historical capture, relative to Brent. Anything unusual going on there, and what should we expect going forward? I'll leave it at that.

Douglas, that price -- adjustment of the price that you see in Egypt, which is lower than what you typically release -- the timings of the liftings, and it's more pronounced this quarter because of the volatility in the prices. We had a bigger drop in prices this quarter. But the key thing to note is there is no change in the underlying pricing of our oil in Egypt.

And the volumes, Tom?

The volumes...

We're -- on a gross basis, we had 13 days of production downtime at the Salam gas plant. That's 200 million a day downtime for 13 days, and the associated condensate production without that gas. That was probably the biggest impact for our overall volumes in the quarter.

Okay, and I guess generally operationally, you're still pretty happy with how things are progressing there?

No different. Everything is proceeding per normal operational program.

Your next question will come from the line of Michael Hall with Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: I guess first on my end, just curious if you might elaborate a little bit on the comment you made regarding the potential interest in accelerating given the improving cost environment. Are there any particular areas that are more compelling? Just looking for maybe a little additional color there.

Well, I'd say, obviously, and I don't think we're the only company in the industry that is experiencing it. We're seeing some significant reductions in frac cost, and we're also starting to see some softening in rig costs. Year-over-year, frac costs are down 25%. So we're beginning to see some impact of rigs coming out of other -- especially the gas areas and going to the more oily areas. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay, appreciate that. And then I guess, as a follow-up on the downtime expected in Australia, can you quantify how long that's expected to be down?

That will be at the end of September, but that's the ammonia plant going down or the fertilizer plant going down.

It's about 3 weeks.

3 weeks.

Your next question will come from the line of Bob Brackett with Sanford Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: I had a question that follows on your pretty active lease round in the deepwater Gulf of Mexico. What's your overall exploration strategy there, given you've such a deep inventory are you going to swing for the fence a little on the deepwater?

Well, certainly, all of those blocks are exploration plays, and the good thing about the deepwater is you get the blocks for 10 years. So we're going to -- we're going to -- we plan on drilling 4 to 5 wells a year, and obviously, they're going to be the best projects that we can find. We do have a backlog of prospects, and we're -- the ones that are the best will come to that. But they're not small. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: But when you say best, is it -- are you going to keep high working interest? Are you going to go for highest risk volumes? Or are you going for things that are more likely to work?

Well, honestly, it's going to be -- we're not going to have 100% of any well we drill in the Gulf of Mexico deepwater. That's a number one premise. Number two, we're going to balance the risk against the size. So some of them will be lower risk, but they're also going to be lower-sized. But in terms of -- we're going to run that program like we do the rest of the company, and that's going to be on a portfolio basis.

Your next question will come from the line of Pearce Hammond with Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: The FPSO, the Ningaloo Vision, seems like operations are running very smoothly. Is that vessel still supposed to have shipyard time next year, or is that maybe delayed?

No, that's correct. It's still on schedule for shipyard time to do some modifications, and you're correct in your assessment about the uptime. In the transition period, we began actually operating the vessel with the contractors' ownership back in February, and subsequent to our involvement with the day-to-day operation, we experienced 95% uptime for the last 6 months. We're very pleased with the vessel's performance. Yet we still have to do the same kind of modifications that we intended to bring the Coniston and Van Gogh projects together in 2013. Pearce W. Hammond - Simmons & Company International, Research Division: And then if you could compare your rates of return on the Gulf of Mexico shelf versus the Central region, it would seem like in the current NGL price environment and gas price environment that the shelf should be a better competitor for activity and for capital than it actually is.

Well, it really has to do with balanced portfolio and risk and reward. Certainly, anything that has liquids with it in the Gulf of Mexico given the rate has a leg up on anything that you drill horizontal, frankly, just because of the profile. But in terms of risk versus reward, the predictability in shales is probably 99.9%. The question is what's the rate? So we try to balance both of those. And if you look at both of those programs, honestly, the Gulf of Mexico was always the highest rate of return projects we can do. I mean, we just got to find good ones to do.

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

Just a question on the Mississippian Lime, can you just give us some sense of how things are progressing there and what are the near-term steps?

Well, we're going to drag in -- a rig in there, here next week, and we're going to drill our first Mississippian Lime horizontal well. And we've honestly -- if you're watching that play, there are some people that have had very good success up there, and we -- honestly I don't expect anything different than that. We have a good position, and it's a question of how long it will it take us to ramp it up.

So no notion on how many you'll drill this year?

We're going to -- I'm sorry. We're going to drill 4 to 6 wells this year. Both there and also in the Bakken.

Okay. And then second question in Argentina. Any comments you can make on this new legislation they're talking about, the submitting of budgets to the government for approval?

We haven't -- other than what we've read in the press, we've interpret the preliminary decree information. We've not had meetings with the government yet. We're currently scheduled to have our first round of meetings with the government per that new decree by the end of September in which case we'll introduce our financial and investment plans for 2013. Now we've, in the past, we have annually produced an investment plan of similar format to the provincial governments. That's been standard procedure. This will be the first time having to do that as a requirement of the federal government. So yes, we don't know exactly what form it's going to take. We don't have the details from them yet on specifically what they want to have us prepare or disclose at the meeting. But that's coming up end of September, and they will have an answer for us within 60 days with regard to the nature of our investment plan and any comments they might have. That's our understanding of where it stands presently.

Historically, we have -- and one of our philosophies down there is to spend our cash flow, and I think in terms of Argentina, that is what they're looking for because they have a number of companies down there, one of which has been in the news forever, and that is they didn't spend anywhere near their cash flow. And I think honestly that's what they're looking for -- who's not spending their Argentine cash flow in Argentina.

Okay. Just one quick follow-up on -- just on Egypt on the realizations asked previously. So can we see that those realizations climb back towards parity with Brent, just subject to liftings times?

Yes.

Yes.

Your next question will come from the line of Leo Mariani with RBC.

Looking for an update on the Kitimat LNG process.

Yes, Janine's here, Janine McArdle who's our Gas Monetization Vice President.

Yes, things are progressing on the Kitimat project. We are still working with our contractor to finalize speed. We're doing a few things to optimize both the design cost and schedule. We're continuing to work with the government on both provincial and federal on some final permitting that we would like to have before we make any decisions. And we're working with, again, multiple buyers in terms of a very long term, 20 to 25-year contracts, and that's going quite well.

Okay, I guess you guys still expect to wrap something up by the end of the year?

So we'll be when we have all those things I just listed completed.

Got you. Okay. Just going over to Australia quickly. What's sort of the plans there on the exploration front for the rest of the year and next year? Because I haven't heard too much about that from you guys lately.

We expect to maintain a 2-rig program pretty much throughout the next 18 to 24 months, drilling combination of exploratory wells, some development or exploitation wells, as well as the key development wells at Julimar-Brunello for the support of the Wheatstone LNG project, as well as the development drilling at our Coniston oil project that is tied to Van Gogh that goes with the Ningaloo Vision FPSO, that we just mentioned in a earlier question.

Got you, and it sounds like your rigs in North America, you've got like 62 of them. You're not drilling any gas. What gas price do you need to see before you start drilling some of the gas targets a little more?

Higher than today.

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

A question on the Tonkawa. You mentioned I think it's about a 10-well, it's at about 310 Mboe or 310 boe IP. I think at your Analyst Meeting, you had a number of wells you talked about and a type curve that was higher than that. And maybe it's apples and oranges, but I just wonder if you could put into context the rates that you're seeing now you talked about in the Tonkawa relative to your expectations.

Well, I think it was over 400 barrels a day, as I recall Rod's comments. The other one is that's a 30-day average and that's actually that makes tremendous economics, and you've got a lot of mix of wells in there.

At the Analyst Day, the type curve we showed for Tonkawa, we're expecting a typical well come on for about 300 [ph] barrels of oil per day. We've exceeded that typically by 10%. We're very pleased with the results of our 30-day average IP basis, and we have a significant inventory of Tonkawa location to be drilled right in the heart of play.

Great, and then when you think about the CapEx required for some of the unconventional NGL transport options such as the rail one that you mentioned. Is that factored into your budget or is that kind of incremental spending to get the better realizations?

That's part of our budget, and it is also part of the full cycle development economics for hitting the fields, which are involved.

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

Any update on Liard Basin? I know you talked about it at the Analyst Day, but is that well still holding up? And I think that was a well from last year. But is that well still holding up, and if so, what's the go-forward plan up there?

Actually, that well is still holding up. We're drilling it -- we're drilling an additional well as we speak. And we're going to drill enough wells, 10-year [ph] wells, in order to hold all our acreage, the vast majority of our acreage.

Okay, so we should just expect one rig running up there over the next year or so. Is that 6 to 12 months? Is that the right we think about it?

Yes.

Okay, moving down to some of the recent acquisitions. I don't -- as far as impairment charges go, is there -- was there any impact from NGLs in the Mid-Continent, like Cordillera acquisition or any other write-downs related to NGLs in the Mid-Continent?

No. I'm not sure what you're alluding to but that's...

Obviously, gas prices impacted impairment charges. I'm just trying to figure out what the impact of NGLs was as far as...

The impairment charge was all Canada.

All Canada, right.

Okay. So nothing -- okay. So you have a cushion left in the U.S.?

Yes.

Obviously some cushion, but how much cushion?

Well, we have 30% of our production in the Central region is oil, and majority of that is black oil. So we're in pretty good shape there. I mean, you can never say never, but it depends on what happens to oil price there.

Yes. All right. And then the final question. I know you said gas prices have to be higher. Let me ask the question in a different way. Whatever number you have in the back of your head for gas prices, how long would they have to get to that level and stay there? Are you looking at a 12-month strip, like 24-month strip before you make the decision? I'm just trying to get the thought process as to when people start looking back toward gases. Do they have to stick there for 3 months or 6 months? Can you just talk a little bit about how you think about that?

Well, number one, I think gas in this country -- most gas wells are going to be challenged and the reason is if you see prices increase, there are so many locations that people can drill gas wells. But what you're going to see is an influx of rigs and people drilling gas wells, and you're going to have -- you're going to run into the same problem. There are some things we could do right now to earn gas price, but we've got a limited amount of capital. And as Tom Chambers pointed out, price differential's about 30 to 1, and it doesn't take rocket scientist to figure out you'll drill an oil well if you got the opportunity. So that as much as what the actual gas price ought to be is really driving what everybody's doing. I mean it's your economics.

Your next question comes from the line of Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Actually going back to the Mississippian and the Williston plays. I heard --I got your point that you've got one rig running in each of those and you think you'll have 4 to 6 wells this year. Is there a time line you have in mind on when you will share your results in those plays? Is there like a certain number of wells you think you have to get down before you can come to a conclusion you want to share?

Well, I think we've got to be satisfied with what the conclusion we reach on both of those. I would expect us to make some results known by the end of the year. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. And what would a rig ramp -- a rig count ramp look like in those plays in the success case?

Well, that is going to have to compete what we've got in the Central region and the Permian region. Certainly with our acreage position, we own a significant interest, 100%, most of the Bakken's stuff, and large interest in the stuff we have with the Mississippian Lime. So it gives us real opportunity to ramp that up if it works. And certainly, the Mississippian Lime is going to work. It's going to have to compete with capital in terms of rates of return with some of the other things we're doing. But Mississippian Lime is -- we're going to drill good wells. It's going to be whether or not -- what the economics are. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. And one other kind of obvious question. Is there anything to add on the political situation in Egypt? I mean, it seems that it has been relatively news-free, at least by those standards, and so that seems welcome. But I wonder if you could add your impressions there?

No, as Rod pointed out, we haven't -- we have continued to deal with the petroleum ministry, the Minister of Petroleum and since have continued to deal with the Chairman of the EGPC. I think Rod mentioned we have 7 new gas contracts that we've just signed. If anything, frankly, what we're seeing is, is that their need for hydrocarbons is such that it may have gotten a little bit better than has been the status quo just because of the urgency nature of bringing production on.

There have been some significant political developments, for them, they announced a new Prime Minister. And he has subsequently appointed new cabinet as of yesterday, and I believe they took their oaths of office today. So we do have a new Petroleum Minister as of today, Osama Kamal, on the petroleum chemical -- petrochemical sector. So there may be some other changes associated with those ministerial changes.

I will now turn the conference back over to Patrick closing remarks.

Thank you, Regina. Thank you for participating in our second quarter conference call. The webcast replay will be archived on Apache's website. The conference call also will be available for delayed playback by telephone for 1 week beginning at approximately 4:00 p.m. Central Standard Time today. That ends our call this afternoon.

Ladies and gentlemen, this does conclude today's conference call. Thank you all for your participation, and you may now disconnect.