APA Corporation (APA) Q3 2012 Earnings Report, Transcript and Summary

Brady Parish - Vice President 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

Arun Jayaram - Crédit Suisse AG, Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Pearce W. Hammond - Simmons & Company International, Research Division John Freeman - Raymond James & Associates, Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Eliot Javanmardi - Capital One Southcoast, Inc., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division Mario Barraza - Tuohy Brothers Investment Research, Inc. Leo P. Mariani - RBC Capital Markets, LLC, Research Division Robert L. Christensen - The Buckingham Research Group Incorporated

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 Third Quarter 2012 Earnings Release Conference Call. [Operator Instructions] I would now like to turn the conference over to Mr. Brady Parish, Vice President of Investor Relations. Sir, you may begin.

Thank you, Regina. Good afternoon, everyone, and thank you for joining us for Apache Corporation's Third Quarter 2012 Earnings Conference Call. For all of you who have been impacted by Hurricane Sandy, we wanted to let you know that our thoughts are with you and your loved ones. This morning, we reported earnings of $161 million or $0.41 per diluted share. Adjusted earnings, which excludes certain items that impact the comparability of results, totaled $861 million or $2.16 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 the 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 will contain forward-looking estimates and assumptions based on our current views and most reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss today. 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, Brady. And good afternoon, everyone, and thank you for joining us today. As I'm sure you've all read in our release this morning, during the third quarter, we accelerated our drilling momentum. Across our portfolio, we've got excellent results. In the U.S., we continued to step up our play activity and now run 63 rigs, 50% more than we did at the beginning -- had at the beginning of the year. And Rod is going to go on a lot more detail, but we've got outstanding well results in a number of plays, including the Cline, Wolfcamp and Wichita Albany and the Canyon Wash and the Permian Basin and also the Granite Wash and the Anadarko Basin. During the quarter, our growing drillbit momentum was also notable on the international front. In the North Sea, after consolidating our expanded portfolio early in the year, we're having very good drilling results with excellent flow rates from all discoveries across our fields. And the value of Apache as operator, I think, has just been endorsed by a major, with Shell last week announcing their purchase of half this [ph] position and many of the Apache-operated fields in the region. In Argentina, we completed our first Vaca Muerta horizontal well, which was a relatively short lateral. It was about 1,900 feet with only 7 fracs. It's early days, but the well results have been very encouraging. We continue to set the economics of the play. We have 4 additional horizontal tests that's planned over the next few months. We have 450,000 net acres in this play, and it has enormous resource potential. After a very successful portfolio expansion phase over the last 2.5 years, we really focused -- refocused back to the drillbit. We hold a leading position in some of the most attractive basins and plays around the world, and we intend to actively exploit this resource potential for the benefit of our shareholders. As we disclosed by our press release last month, our third quarter reported production reflects approximately 25,000 barrels of oil a day of production downtime, which were due primarily to hurricane disruptions in the Gulf of Mexico and the scheduled North Sea platform turnarounds. Our third quarter production averaged about 771,000 barrels a day. And if you put 25,000 barrels on top of that, which is all back on right now, we're -- we've -- we're producing today approximately 800,000 barrels a day. The important thing is we remain on track to deliver our production growth guidance for the year and we're going to stay within our $10 billion exploration and development budget. One final note. And as we continue to build and execute our global pipeline of exploration activity, we're testing 2 wells, 1 in the Williston Basin -- both which we have large acreage positions; and the Mississippian Lime. The good news is we've had good oil shows from the logs and the formations that we were targeting. We're currently completion -- in the completion phase of our initial wells in each of these plays, and we'll be experimenting with our frac designs to give us optimal results. We secured a number of blocks in the recent Gulf of Mexico lease sale. We have captured a highly sought-after deepwater block in Suriname, which is on trend with recent play opening and discoveries. You should expect our drillbit momentum to continue. We have built the foundation of this portfolio over the several years, and this is personally the most exciting time for me over the last 25 years. We have the asset depth, financial strength and delivery expertise to stand out in this sector, and that's exactly what we intend to do. Now I'll turn it over to Rodney.

Thank you, Steve. Our total reported net production for the third quarter was approximately 771,000 boe per day. Hurricane Isaac in the Gulf of Mexico and outages in the North Sea due to scheduled maintenance activities reduced production by 13,000 boe per day and 12,000 boe per day, respectively. Currently, all of this production is back online and we have entered the fourth quarter with record worldwide net production. During the third quarter, we continued the conversion of our extensive onshore oil and hydrocarbon liquids-rich inventory into production and cash flow. We rank among the most active drillers in North America, having operated an average of 66 drilling rigs in our U.S. regions during the quarter, including 35 in our Permian region and 24 in our Central region, with outstanding results. Our Permian and Central region averaged combined net production of approximately 184,000 boe per day during the third quarter, nearly 1/4 of our total worldwide net production. Moreover, this represents an increase of 15% over the second quarter averaged net production of 160,000 boe per day and an increase of 30% over third quarter 2011 net boe production of 141,000 boe per day. With the inventory of over 67,000 locations in these 2 regions alone, we remain on track to deliver double-digit growth in the oil and liquids-rich Permian and Central regions for years to come. In addition, we are continuing our very active new venture exploration program. Steve already elaborated on our encouraging results in the Mississippi Lime and Williston Basin and Vaca Muerta shale, so I'll not address these plays here. In Alaska, we are on track to spud our first well in the Cook Inlet during the fourth quarter. Finally, in October we signed a new production shoring agreement to explore a high-potential area in Block 53 offshore Suriname in the equatorial margin fairway. We were awarded 100% interest in this block and expect to commence a 3D seismic program during 2013. Now turning to more detail in our regions. The Permian had another outstanding quarter as we continue to grow through drillbit. Third quarter production averaged nearly 112,000 barrels of oil equivalent per day, a 7% increase over the second quarter, with part of the increase resulting from additional NGL processing at the Deadwood plant as it became fully operational. Our substantial acreage position continues to provide Apache the flexibility and optionality to test new plays and concepts. During the quarter, we added 230,000 gross acreage to our overall acreage position, the majority of which was in the Midland Basin and the Wolfcamp play. We now hold over 3.7 million gross acres across the hydrocarbon-rich Permian Basin. We are now the most active driller in the basin and, during the quarter, averaged 35 rigs, drilling 201 wells of which 26 were horizontal. We expect to continue our shift to more horizontal drilling in the fourth quarter and into 2013 when we anticipate nearly half of our drilling rigs will be horizontal. Drilling at Deadwood and Yeso continue to be a large contributor to growth, while Irion County Wolfcamp horizontal activity and potential continues to expand. At Deadwood where we are targeting the Wolfwood and Fusselman with vertical wells, we averaged a 15-rig program for the quarter. Earlier in the year, we acquired additional 3D seismic data, with the first migrated data arriving earlier in third quarter. This new seismic information greatly enhanced our ability to target the prolific Fusselman accumulations, and new locations are continuing to be identified. A couple of our most recent Fusselman successes are the Squire 9 #5 well, which flowed at 339 barrels of oil per day and 677 Mcf per day; and the Reilly [ph] 37 #8, which produced at a rate of 166 barrels of oil per day and 256 Mcf per day. Drilling in the Deadwood area will complete the main active throughout 2012 and into 2013. We operate 2 horizontal rigs in the Deadwood area, targeting the shale of the Wolfcamp, Atoka/Barnett and the Lower Cline formations. The latest Cline well in Deadwood is Apache's best well to date. The [indiscernible] 45-2H was drilled on the Southeast edge of our Deadwood acreage. The well was drilled to a TD of 13,350 feet measured depth with a 1,300-foot lateral, and after an 11-stage frac, the well obtained a peak rate of 810 boe per day. The well has averaged 623 boe per day in its initial 30 days production and has produced nearly 26,000 barrels of oil equivalent to date, with a preliminary EUR of about 600,000 barrels. The average EUR of the last 5 Cline wells is now 452,000 [ph] barrels. Also in Deadwood, a lower Wolfcamp Deadwood shale lateral was drilled 1,300 feet to a TD of 12,900 feet measured depth and tested at peak rate of over 200 barrels of oil per day and 200 Mcf per day. Additional appraisal wells are planned for the Wolfcamp and Cline shale plays in 2013, and commercialization of these shales could add hundreds of potential locations to the 560 locations already identified in the Cline shale. We have additional -- also drilled a horizontal well in the Barnett Shale. And after a 14-stage frac, the peak rate exceeded 380 barrels of oil per day and 613 Mcf per day. In the Barnhart Wolfcamp play, Apache has drilled 13 wells, 8 producing and the remainder either in drilling or frac-ing or flow-back stages. Since March 2012, these 8 wells have produced 234,000 barrels of oil and 509 million cubic feet of gas or 319,000 boe from the upper Wolfcamp Shales only. Current Wolfcamp production is 2,150 boe per day. Two middle camp -- two middle Wolfcamp wells are currently drilling, and a Cline horizontal well on Ketchum Mountain will spud soon. In the other Midland Basin and eastern shale properties, we have had some notable results in the Wilshire area such as the well at McElroy Ranch that tested as high as 289 barrels of oil per day and 735 mcf a day from the Spraberry through 10 [ph] intervals on a submersible pump. In the Yeso area of New Mexico, we ended the quarter running 4 vertical rigs. 27 vertical wells were spud during the third quarter and 22 wells are completed and producing. Notable wells from the quarter include the Lee Federal #59, which averaged 168 barrels of oil per day and 403 Mcf per day during September; and the Tony Federal #39 whose 30-day well test averaged 119 barrels of oil per day and 287 Mcf per day. Our fourth rig, recently transitioned from drilling vertical wells to commencing our multiyear Shear [ph] Lake horizontal drilling program. We continue to have good results from the Central Basin Platform where we are applying horizontal drilling to historically conventional fields and reservoirs with outstanding results. In the Three Bar shallow unit, we have tested the Wichita Albany, an interval characterized by air bed [ph] limestones and dolomite frosty zones at measured depths of 7,000 feet. Results from the first 2 wells include the 10-1H, with a 30-day average production of 848 barrels of oil per day and 465 Mcf per day, and the 105-H, with an 18-day average production of 620 barrels of oil per day and 754 Mcf per day. We plan to run one rig in the unit during the fourth quarter. As we drill more, we learn more, and we are able to improve the efficiency of our exploration and operations activities, as evidenced by these widespread encouraging results. We continue to be excited about the abundant opportunities and growth prospects of our Permian Basin position. In our Central region, we are also seeing excellent results in new ramp up activity across our nearly 2 million gross acres. Production was 72,300 boe per day, up 31% from the second quarter. Adjusting for acquired Cordillera production, growth was 24% quarter-over-quarter as we realized the benefits of our active oil and liquids-rich drilling program. The growth was driven by a 42% increase in oil production and a 20% increase in gas production. Our opportunities in the region continue to expand, following our May acquisition of over 312,000 net acres and subsequent 18,000 additional acres in the heart of the Anadarko Basin. During the third quarter, this region operated an average of 24 drilling rigs, 23 of which were horizontal and drilled 40 wells with 100% success. During the same period, we completed 26 new wells, for an average daily rate of 485 barrels of oil per day and 2,700 Mcf of gas per day. We continue to work numerous plays across our acreage position. Notable highlights in the quarter include strong results in the oily Tonkawa, Marmaton and Cottage Grove, a new horizontal play we're testing on our Stiles Ranch, and other properties. In the Tonkawa, for example, our Karen 1-25H averaged 525 barrels of oil per day at 1.8 million cubic feet gas per day for the first 30 days of production, and the Steward 1-20H averaged 654 barrels of oil per day and 758 Mcf per day. In the Marmaton, we also had positive results, including the Standing [ph] Eagle 1-16H, which averaged 514 barrels of oil per day and 5.8 million cubic feet of gas per day and the Maddole [ph] 1-18H, which averaged 1,116 barrels of oil per day at 8.9 million cubic feet of gas per day. The Cottage Grove also provide strong results, with the Stiles 24 68H averaging 893 barrels of oil per day and 1.2 million cubic feet of gas and the Stiles 12-1H averaging 1,652 barrels of oil per day at 1.6 million cubic feet of gas per day. The Granite Wash continues to be a significant focus of our drilling program, and during the quarter, we tested the Weatherlee [ph] 6-1H, which averaged 672 barrels of oil per day and 5.7 million cubic feet of gas per day. In general, we were finding enough oil in the Granite Wash that remains economic despite low NGL prices. In the Texas Panhandle, drilling success continues in the Canyon Wash on our 200 square-mile Bivins Ranch acreage. During the quarter, we completed our 9th and 10th successful wells, which tested 1,050 barrels of oil per day and 950 Mcf per day and 1,447 barrels of oil per day and 1,199 Mcf per day. This is an encouraging validation of Apache's play concept. Keep in mind, these 1,000-plus barrel a day wells are for vertical wells. To debottleneck our growing production, we completed a 9-mile pipeline in transport stranded natural gas during the quarter, thereby securing our takeaway from the area, which has grown from 0 to over 5,000 barrels of oil per day in 14 months. The line is currently selling 3.3 million cubic feet of gas per day of 1,450 BTU gas with NGL recoveries. Additionally, we added a second rig in the Bivins Ranch area. During the third quarter, low ethane prices at Conway resulted in ethane rejections for the region. The ethane rejection was limited to the month of July and August as ethane prices at Conway dropped to record lows in early July. At that time, Conway ethane was trading at approximately at 90% discount to Mont Belvieu. In the end of the third quarter, this discount was reduced to approximately 42% to Mont Belvieu. Currently, Conway ethane is discounted 44% to Mont Belvieu. Turning to the Gulf of Mexico Shelf. Quarterly production was down 8% to 90,000 boe per day as a result of approximately 10,000 boe per day of curtailments due to Hurricane Isaac. This was due primarily to the storm's impact on third-party facilities as Apache's infrastructure was relatively unharmed. With shut-ins behind us, we are currently running 8 rigs, 2 of which are focused on P&A work, year-to-date, we have TD-ed 21 operated wells, offsetting some of the downtime experience during the quarter with positive well results with our shelf drilling program. For example, the Main Pass 315 well came online at 634 barrels of oil per day and Eugene Island, the 118 B#1, sidetrack penetrated 45 feet of gas and a few [ph] sand. At Ship Shoal, the 126 B well came online at 522 barrels of oil per day and 3.8 million cubic feet of gas to date. And 2 new wells at Main Pass 308 came online for a combined rate of 1,555 barrels of oil per day. The total platform rate is currently 2,596 barrels of oil per day, but production is being curtailed due to facility restrictions. Modifications are currently being designed to remedy the situation. We've now been awarded 60 -- 61 blocks from the June 20 federal lease sale, adding to our inventory of opportunities in the Gulf. Looking ahead to the fourth quarter, we plan to increase our rig count by 1 when a rig finishes the 7-month shipyard project. By the end of the quarter, we plan to complete the Main Pass 308 drilling program. The last location is drilling and one recompletion is remaining. Our Eugene Island 330 drilling program will also continue through the end of 2012, with 2 additional locations to be drilled. In the deep Gulf, third quarter production was relatively flat as a full 3 months of production from our Wide Berth and Mandy fields was offset by Hurricane Isaac downtime. We anticipate bringing our Bushwood field near future as capacity is freed up from [indiscernible] depletion. This will add approximately 4,500 net boe per day to the region's production. During the second quarter, we announced our participation in the June 20 Central Gulf of Mexico lease sale. The awards have now been completed and we received 28 blocks. During 2013, we are taking delivery of 2 rigs to begin exploring these prospects. In our Gulf Coast Onshore region, average production was up 8% over the second quarter to 27,000 boe per day as additional takeaway capacity was installed at our Atchafalaya Bay field and production was reestablished in the Lake Paige Field. These additions, coupled with new production volumes and continued drilling success at our Chapman Ranch in South Texas and Golden Meadow Fields onshore Louisiana helped to offset production deferrals due to Hurricane Isaac. A notable highlight from this region was the Scottsdale [ph] #1 well in South Louisiana, which tested 20.2 million cubic feet of gas per day and 199 barrels of oil per day at 47-degree API gravity oil. We plan to complete the installation of a 4-mile, 8-inch flowline connecting the well to our Atchafalaya Bay production facility before year-end. Apache's Gulf Coast Onshore region initiated production this morning to a newly installed 12-inch pipeline connecting our Atchafalaya Bay production facility to TransCanada or ANR's 30-inch pipeline 5 miles away. We are currently ramping up production to 50 million cubic feet of gas gross per day, with plans to increase production to 75 million cubic feet of gas gross per day over the next few days. This marks the completion of Phase 1 of our Atchafalaya Bay infrastructure project. Phase 2 is anticipated to be complete during the second quarter of next year, which will bring gross production from our Atchafalaya Bay wells up to 220 million cubic feet of gas per day, an increase in current producing rates by an incremental 170 million cubic feet of gas per day. Apache has a working [ph] interest of approximately 48% to 50% in these wells. Looking ahead, we intend to have 6 operated rigs running during the fourth quarter as we focus our efforts on oil opportunities in Southeastern Texas, Southern Louisiana and Southern Mississippi. Heading north to Canada. Production in the third quarter was steady as the region continued to transition to more oil and liquids-rich production. Drilling has focused on several plays across our extensive acreage position such as Dunvegan, Bluesky and Sparky. Well highlights from these areas include the first 3 of 4 operated Dunvegan horizontal oil wells in the Kaybob area, with 1 well already in production. Initial oil rates range from 159 to 320 barrels of oil per day. Drilling of the fourth well and production start-up of all wells will occur in the fourth quarter. In the liquids-rich Bluesky area, we continued our horizontal program, completing 3 wells during the quarter. Very strong results received, particularly in the third well which tested at 11.7 million cubic feet of gas per day and 600 boe per day of liquids. Lastly, the Sparky program in the Consort area continues to play a significant role in our program. And during the quarter, we operated 3 rigs and drilled 24 wells. Oil production in Consort increased from 1,250 barrels of oil per day to 1,792 barrels of oil per day in the third quarter, of which Sparky program provided 300 barrels of oil per day, with 1/3 of the third quarter drills tied in and proving up. Production start-up of the remaining wells will occur in the fourth quarter. Moving outside North America in the North Sea. Third quarter production average 67,800 barrels of oil equivalent per day was down quarter-over-quarter due to turnarounds and continued challenges with ESP failures, as previously disclosed, resulting in deferrals of approximately 12,000 boe per day. All operated Forties platforms are back to full production, as are Scott and Telford. Nelson is scheduled to return to production in mid-November. During the quarter, the region operated 4 rigs and drilled in the produced 6 gross wells with 2 further wells in progress. Well highlights for the region included Bacchus West, the second-successful horizontal development well in the Bacchus Field. The well encountered 889 feet of net pay in the Jurassic Fulmar sandstone reservoir. It was completed in late July, with initial production of 8,500 barrels of oil per day gross. Apache is the operator in the field with a 50% working interest. The Bacchus Field commenced production in May of this year and is currently producing around 10,000 barrels of oil per day, 5,000 barrels a day net, through the subsea tie-back to Apache's Forties Alpha platform. Looking to Forties. We also brought on 3 new wells with average IP of 1,633 barrels of oil equivalent per day. We made continued progress on the installation of the Forties Alpha Satellite platform. The jacket was installed successfully west of the Forties Alpha platform on September 8. The platform topside will be lifted into place in the second quarter of 2013, followed soon thereafter by development drilling through its 18 well slots. We continue also to have drilling success in our Beryl field where, during the quarter, Apache's Beryl Bravo's B73-Y [ph] development well tested at 8,161 barrels of oil per day and 5.9 million cubic feet of gas per day from a Jurassic Manson [ph] reservoir containing 71 feet of net oil pay. The well began producing at the end of August. The well also encountered 245 feet of net pay in 3 additional zones that will be produced in a later date. We have a 50% interest in the well. The U.K. Department of Energy and Climate Change announced this month the award of 11 new North Sea licenses to Apache, the highest of any operator participating in the 27th Seaward Licensing Round. These awards covered 19 full or partial blocks, 613,000 gross acres or 2,482 square kilometers. Included in these blocks is all the available acreage around our Beryl field plus 2 key licenses near Forties. Apache also was awarded an interest in another non-operated license. The economic prospectivity of these areas was enhanced by recent improvements in the U.K. tax allowance mechanism involving small fields in high-pressure, high-temperature formations. Looking to the fourth quarter, we plan to drill wells on Forties Charlie and Forties Echo as well as reinstating wells on Forties Bravo and Forties Delta. The Beryl Bravo platform will be down for a planned par [ph], which started 26 October, returning to full production on 22nd of November in order to perform routine maintenance. Turning to Egypt. Our operations continued unabated. We averaged 26 rigs operating and reported quarterly averaged net production of 153,000 barrels of oil equivalent per day. Because of the terms of our PSC to provide for lower nets with higher oil prices, we reported a 4% decrease in the preceding quarter. On a gross basis, however, we essentially held production flat. In addition, during the quarter, we saw record turnarounds on development lease approvals after seeing delays of 9 months or more during 2011. The most recent approvals for development leases took just 34 days, a positive sign that the new leadership at petroleum ministry EGPC is finally finding its footing. In Khalda, we had several discoveries of note this quarter, including the Samaha North 1X [ph] which drilled to a TD of 17,362 feet in the Lower Safa. The well encountered pay intervals in 4 zones, and a test is pending. The earlier discovery, Samaha 1X [ph], tested at a rate of 20.8 million cubic feet of gas per day and 913 barrel of condensate per day from the Lower Safa and 23 million cubic feet of gas per day and 1,997 barrels of condensate per day for the Upper Safa. And the Samaha East 1X [ph] tested at a rate of 28 million a day and 711 barrels of condensate for Lower Safa and 14.5 million cubic feet of gas per day and 1,110 barrels condensate for the Upper Safa. KPC or Khalda Petroleum Company's current oilfields also saw a high level of activity. During the quarter, a total of 13 wells were drilled or are currently being drilled in these properties. In the Eunice field, 7 wells were drilled, including 3 injectors. And recent initial tests of the Unis 2 Upper Bahariya reservoir resulted in 1,800 barrels of oil per day. The Eunice field started production this year and, as of October, is already producing in excess of 5,500 barrels of oil per day gross. Looking to Australia. We continue to make significant progress toward development of our large infrastructure projects in the region. The BHP-operated Macedon project is reported to be over 70% complete and on schedule for first gas in mid-2013, which will add approximately 45 million cubic feet of gas of net production when 2 new contracts come on in 2013 and 2014. All contracts have been executed on schedule for our Balnaves project, with the Armada Claire FPSO currently in the shipyard undergoing refurbishment and replacement construction preparing for Balnaves 2014 [indiscernible]. Our Julimar gas development in support of the Wheatstone LNG project is progressing on schedule, with recent contract awards announced for various subsea project components. Third quarter net production was 64,000 boe per day or 3% down from the previous quarter likely [ph] due to anticipated decline at the Van Gogh field. Looking ahead in the fourth quarter, 2 new wells both commenced at Stag in late October, while Van Gogh and Pyrenees are forecast to continue declining slowly through the remainder of the year. The first Stag well, the Stag 44H, came online this week and is currently producing 1,800 barrels of oil per day, adding to the Stag 45H production that came on the week before at around 1,500 barrels of oil per day. A planned turnaround of the Yara fertilizer plant that began in late September has experienced delays to an unexpected equipment failure. It is anticipated by our partner, the operator of the plant, to be offline until late November. Offsetting these deferred volumes at Yara are recently signed commercial gas contracts for additional Reindeer and John Brookes volumes in the fourth quarter. Finally, in Argentina, production during the quarter averaged 48,000 boe -- 48,500 boe per day, a 3% decline quarter-over-quarter. During the quarter, our total Gas Plus production averaged 111 million cubic feet of gas per day out of 214 million cubic feet of gas per day of total net production, with 98 million cubic feet of gas per day or 88% of the volume sold at Gas Plus prices which averaged $4.97 per Mcf. In the Neuquén Basin, we drilled and completed successfully the NL 62 well at 2.5 million a day from the pre-Cuyo formation. The well has been approved at Gas Plus, and we are currently selling gas at $5.47 per Mcf. In total, the Neuquén Basin 7 wells reached TD in the third quarter under Gas Plus, and a total of 8 wells were initially completed, delivering a combined growth rate of 17.1 million cubic feet of gas per day and 1,595 barrels of oil per day, which is 4,445 barrels of oil equivalent per day. As Steve already mentioned the encouraging initial results for our Vaca Muerta exploration program, I won't elaborate further here. That concludes our many operational highlights. And I'll now turn it over to Tom Chambers.

Thanks, Rod. And good afternoon, everyone. As Steve and Rod mentioned, we are actively focused on our significant inventory of drilling opportunities and realizing the potential we've built through these acquisitions. Record rig counts continue to increase in our Permian and Central regions, and significant infrastructure investments in all the regions has set the groundwork for a positive momentum adding into year-end. Underpinning this activity is our ability to generate strong consistent revenues and cash flow. For the third quarter, we reported earnings of $161 million or $0.41 per diluted share and adjusted earnings of $861 million or $2.16 per share when we adjust for certain items that affect the comparability of results. Third quarter adjustments totaled $700 million and include a noncash property write-down in Canada, a change in tax rate on decommissioning expenditures for North Sea oil and gas facilities, a foreign currency fluctuation adjustment and some small merger acquisition and transition costs. The noncash after-tax write-down of our Canadian oil and gas properties totaled $539 million, which brings the year-to-date amount to $1.4 billion. Our Canadian regions reserves were over 77% natural gas at year-end 2011 and a decline in natural gas prices over the prior year continues to impact us under full-cost accounting rules. The other large noncash item impacting earnings was the $118 million charge related to decommissioning facilities in the North Sea. As you'll recall, in 2011, the U.K. increased the corporate income tax rate on North Sea oil and gas profits from 50s -- 50% to 62% and at that time also proposed that the tax relief attributable to decommissioning expenditures remain at 50%. The decommissioning-related legislation was not formally enacted but was included in the finance bill introduced in 2012 and enacted in July of this year, necessitating the change in the quarter. Production drove results in this quarter and fueled our -- fueled by our extensive drilling program. Production averaged 771,000 barrels of oil equivalent a day, a strong performance despite downtime in the Gulf of Mexico associated with Hurricane Isaac and maintenance downtime in the North Sea. Higher oil prices contributed to the total revenue of $4.1 billion for the quarter and a record $12.6 billion on a year-to-date basis. This compares to $4 billion in the previous quarter and $12.5 billion year-to-date in 2011. Our revenues and, ultimately, our ability to maintain operating margins translates into cash from operations which totals $2.4 billion for the quarter. Cash flow from operating activities before changes in working capital was 2% higher than the previous quarter. Year-to-date, our cash flow from operations was down only 2% over the prior year-to-date period despite lower worldwide price realizations, with natural gas and NGL prices down 16% and 27%, respectively, and oil prices up only 2%. International price realizations helped to mitigate the decline in the quarter in earnings and cash flow, with oil price realizations up 10% sequentially and 3% from the prior year quarter. Additionally, with Brent currently trading at over a $20 premium to WTI, we will continue to reap the benefits of our global oil position. International natural gas prices were up 3% from the prior quarter and 13% from the third quarter 2011. For the past 3 quarters, we have realized over $4 per Mcf on our international gas production, a significant premium to North American prices which average well below $3 per Mcf over the same time frame when we exclude the impact of hedges. International regions represent just over 1/3 of our worldwide gas production. A key point I'd like to emphasize is that both international oil and gas price realizations were 20% higher than North American average realizations, a true testament to our global portfolio of balance and reach. Our cash margins for the third quarter remained strong. At $41.54 per boe, our cash margins increased 5% from the sequential quarter but decreased almost 10% from the prior year period. Our cash costs were slightly higher than we would have liked to see this quarter, particularly lifting cost, which were primarily impacted by an increase in nonrecurring repairs and maintenance costs tied to corrosion repairs at our Grand Isle facilities and plant turnarounds in Canada and the North Sea. We also increased workover [ph] activity in nearly every region. Besides providing very good rate-of-return projects, they supported our base production. Coupled with the continued growth in our onshore North American operations, our labor costs have increased accordingly. As production rises in the fourth quarter and into next year, our rates should fall back accordingly. Rest assured we will remain focused on optimizing our margins and managing our costs while not compromising safety. You can find a detailed calculation of our margins, adjusted earnings and cash from operations in the financial supplement located on our website. Turning to the balance sheet. We have continued to maintain a strong and flexible balance sheet, with a debt-to-cap ratio of 27%. We ended the quarter with $318 million in cash and a total debt of $11.6 billion. Moving on to taxes. As I mentioned on the prior call, our earnings would be impacted this quarter by a change in U.K. tax law, which it was, and I detailed earlier in my comments. The third quarter effective tax rate of 79% was impacted by this charge in the Canadian ceiling test adjustment as well. Absent these adjustments and foreign exchange movements, our effective tax rate would have been a more typical 45%. We would expect a deferred tax percentage of approximately 20% for the year, absent these adjustments. In closing, we had another solid quarter of production revenues and cash flow driven by our drilling program. And with that, I'll turn the call back over to Brady.

All right. Thank you, Tom. That concludes our prepared remarks. I do want to apologize to the listeners on the call if you hear any background noise. But I'll turn it over to the operator now, and we're ready for questions.

[Operator Instructions] Our first question will come from the line of Arun Jayaram with Credit Suisse. Arun Jayaram - Crédit Suisse AG, Research Division: Steve, we've seen some pretty interesting announcements regarding majors, including Exxon, I think, some pretty high valuations for Canadian gas acreage. I just wanted to see if you could maybe comment on some of the potential implications for Apache. Are there opportunities for you to monetize some of your acreage in places where you're not spending capital? And does this have any implications? Could you partner with Exxon regarding Kitimat where the market is concerned about?

Two different questions. I'll take the first one, about the acreage. Interestingly -- and I think the number is correct because I asked our guys and gals in Canada. We have about 300,000 acres in that same play that just traded. And in fact, we're starting to drill some wells there at the end of this year and in the first of next year. How we actually exploit all of that acreage? We got 6.5 million acres in Canada and we just went through the same process that we've done in the Anadarko Basin and the Permian Basin in the -- in our Canadian region in terms of resource potential, and we're going to be rolling that out here in the coming months. But the potential for liquids and liquids-rich gas in Canada are actually much stronger than I thought they were. In terms of partnering with Exxon, I can't comment on that. But despite some of the things you hear in the press, we're -- Kitimat is still going forward, and we have -- we're very positive about it. Arun Jayaram - Crédit Suisse AG, Research Division: Okay, I'll leave it at that. Obviously, Steve, this year, you've had some production disruptions. It sounds like those are in the rearview mirror. How comfortable are you, Steve, with your 6% to 9% target for 2013? And I just wanted to also see if we could get a little bit more color on the next couple of quarters for the North Sea given -- with the ESP issues back online, things like that. So some more color on the North Sea.

Yes. In terms of -- there's nothing -- honestly, if you -- and I -- this is an excuse and I don't like to give excuses, but if you were to adjust our production, which you can't do because we didn't get the cash and we didn't get the production, but if you were to adjust it, we would have been right on our -- for the hurricane, which you can't do a damn thing about, and the events in the North Sea would be right on our production forecast. And I know that sounds like an excuse, but as we move to the drillbit, those kind of things, we've got to get over. We've got to get past those kind of things. So far, I will tell you, from an outlook for the fourth quarter, we're very positive about it. And there's nothing changed with respect to our forecast for 2013, 6% to 9%. I mean, I think we have the inventory and we have the asset base in order to do that.

Your next question will come from the line of Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: A question on Beryl. If anybody knows what the value of Beryl is, it's you folks. You saw Shell take out Hess' interest. What's the sense there? Why didn't you either match or beat the bid? And is that a sign that you got too many things to do and you don't want to do more bolt-on acquisitions?

I really can't comment on that at the present time. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay, I'll try again, moving to a different country. Can you -- a bit more color on the Vaca Muerta then?

Yes, I will. We're a -- it's a little early to give rates. I will tell you we were pleasantly surprised by the initial rates that we got out of that well. We've been -- we've had it on now almost a month. I will tell you, it's still making 300 barrels a day. And for a well that's been frac-ed 7 times in only 1,900 feet of lateral, it's -- we're very satisfied with it.

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

I -- a couple for me, please, if I may. Steve, it's obviously pretty nice to start seeing the momentum picking up in the Lower 48. Can you tell us where you see the rig count going in terms of relative capital allocation between, I guess, international and U.S., particular, Lower 48 in particular, 63 [ph] now. Where do you think that tops out? Or are you at a level now where you think you're -- you've got enough to say grace over?

Well, I think -- as I said in my prepared remarks, I think you're going to see that momentum build. Certainly, from an opportunity standpoint, we have the opportunity to -- and I'm going to be redundant. But if you remember in 2010, we spent $500 million in the Permian, then we went to about $1 billion. This year, we're going to spend a little over $2 billion, and in next year, we're going to spend more than that. We'll probably run 40 rigs next year in the Permian. And the Anadarko Basin, our results there, actually better than we expected. So we're going to -- you're going to see an increase in the Anadarko Basin also, which speaks to the allocation of capital. Certainly, we haven't allocated our capital for 2013 yet. We're going to do that in December. But it's certainly -- we're going to put it into best projects, wherever those projects are.

And then Steve, this might be a dumb question as a follow-up, but I'm going to have a go, anyway. Your stock prices, when you did the BP deal last time, your share equity was above where the share price is now. You obviously -- you've done Analyst Day, you've given us insight to everything that's going on, and you spent a lot of money buying assets. As you say, you've got a very deep portfolio. One could argue that you could buy back reserves cheaper by buying back your own stock. I'm just curious as to how that plays into how you're thinking about trying to address some of the recent performance in the share price which seems to contrast with the tremendous portfolio you've built up.

Yes, and I -- we've had this discussion before. I think, in terms of the rates that we're getting for the investment dollars that we have in our portfolio -- it's -- other than perception, would be rates of return, which would be cost of capital to buying our stock back. We're not -- at the present time, we're not considering diverting capital from the base program to buy our stock back.

So what do you think it is the market is missing here? Because I'm just really going to take your perspective as to how patient you're going to be on this.

Well, I -- the -- I -- obviously, we're disappointed that we had the down time. I'm optimistic that we'll have a good quarter in the fourth quarter and I think we got to continue to post quarters.

Your next question will come from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: I was just curious, just thinking broadly about 2013 CapEx spending. Is it roughly fair to think, in terms of it mirroring the growth in cash flow year-over-year, that it might move up in lockstep with that?

Yes, we're going to -- we have the opportunity base. It's -- we're going to spend our cash flow in the E&P business. Pearce W. Hammond - Simmons & Company International, Research Division: And then a second question is to follow up if you can kind of broadly compare and contrast the economics and opportunities of LNG projects in Australia versus those in Canada.

Well, for different reasons, they're very similar, actually. I mean, obviously -- let's assume that the pricing of the LNG is exactly the same in Australia versus they are in Canada. I will tell you a -- the add-ons of trains in Canada would be much more lucrative than they would be in Australia just because of the cost. So that project really is a long-term project. And there's tremendous amount of gas in the United States and/or in British Columbia right now.

Your next question will come from the line of John Freeman with Freeman James (sic) [Raymond James]. John Freeman - Raymond James & Associates, Inc., Research Division: I didn't know that I took over the company. The -- on the North Sea, the 12,000 that was offline, the -- specifically just to the ongoing pump issues, how much of the 12,000 was related to just the pump issues?

It's only about 2,000 or 3,000 barrels of oil per day specifically attributed to the pumps. We had 9 ESPs that were off and those are being cycled into the drilling, scheduled to be replaced, along with new drills that we do that -- based on economics so that -- we haven't got all of those 9 replaced yet, but they probably will be by the -- in the second quarter of 2013.

But the real down -- production off was the -- was our turnaround at Alpha. John Freeman - Raymond James & Associates, Inc., Research Division: Right. And I think you all mentioned that Nelson returns in November. How much of a production impact is that?

That's 1,900 barrels of oil a day net. And that's been down for about almost 100 days. John Freeman - Raymond James & Associates, Inc., Research Division: Okay, great. And then last question for me, it's still on the North Sea. Did the 3D seismic killer [ph] you're shooting on Beryl, did that get completed last month?

It's only partially completed. We have about -- 30% of it was acquired in the current shooting weather window this last summer. The balance of it we acquire in 2013.

But the 40% is we're currently processing.

Right.

Your next question will come from the line of John Herrlin with Societe Generale.

Just some quick ones for me. With Suriname, will you shoot the seismic and then bring someone out to promote [ph] ?

Yes, well, let me put it this way. We're not that -- we wouldn't go drill that well 100%. And we -- and -- but frankly, John, we've already had a lot of interest. That's a very good block, frankly.

Yes, I would assume so. Yes, Atlantic margin turbidites are in. What about services cost, Steve? We're seeing -- or hearing on a lot of the other conference calls that prices for rigs and frac-ing are coming down. What are you seeing?

Oh yes, they're -- actually, frac-ing costs came down really in the third quarter in a big way, and you're starting to see rigs come down. If you look at the rig count in the Permian Basin over the last 2 months, I mean we're -- it's the historic or the continuous ebb and flow of prices, service costs and capital. And what you're seeing right now is we were on the back end of all those service costs going up, we're on the front end of it now because we -- I think they'll continue to go down.

Okay. Last one for me. Would you consider ever doing not a stock buyback but a more competitive common stock dividend? You've got a great balance sheet, you're very diversified and you're suffering benign neglect.

I -- we did that many years ago, actually. And I mean, honestly, we consider pretty much all avenues of what -- how to reward our shareholders, frankly, from a cash dividend to a stock dividend to stock buybacks. And frankly, when you look at our portfolio, all we have to do now is deliver honestly. Our -- as I told our planning meeting group, we have 280 people in Dallas and we have nobody to look at but ourselves. We just need to perform because we've got the asset base and we've got the people, so...

Okay, last one for me. Steve, would Mississippi Lime be a good water disposal access?

I'm sorry. What, John?

Would the Mississippi Lime be a good water disposal access, wells being wells.

Yes, you're going to -- I mean, you're going to get -- yes, it would. I mean, that -- if you've looked at not just us but all the operators out there, that's a good oil play, but you've got to move a lot of water, which we anticipated.

Your next question will come from the line of Matt Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick questions for me. Firstly on the CapEx side. Looking at Q3, it looks like the run rate CapEx spend is about $2.7 billion for drilling and then also gathering. Is that a reasonable rate that we should think about going forward? And then as we head into 2013, kind of can you talk a little bit about the rig count that you're currently employing by basin and then -- and how that may change over time? I think you mentioned the Permian will increase to about 50% horizontal rig. So I'm just trying to get a sense of how those rigs are shifting around.

I think we've got 34 rigs. I mean, I might be off one, but I think we have 34 rigs in the Permian. We've got 24 or 25 in the Anadarko Basin. I think we're up to 7 in Canada and we've got 8 offshore Gulf of Mexico. That's not exact, but that's pretty close.

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

Can you refresh us on Australia, on production trajectory and your latest thoughts on Van Gogh platform remediation and just what we should expect production trajectory-wise over the next 4 to 7 quarters?

Yes. I mean, Van Gogh has been very good. It's paid out 9 months. We're still producing, I think, about 16,000, 17,000 barrels a day there. We have a turnaround on our FPSO coming in about the middle of -- I mean, middle of 2013. And the real reason that's important is we're going to -- when we bring it back. In the meantime, we're going to be drilling Coniston wells, which is a sister field to the north of Van Gogh that will start ramping up our oil production going through that FPSO. But frankly, we've seen the peaks of the production at both Van Gogh and Pyrenees. And the way we replace that is we've got Balnaves, which is about a 20-million-barrel oil field we should have on broad win [ph] 2014.

2014.

2014. We also got Macedon, which is gas, but it's not like North American gas. It is -- that contract is north of $7. So we've got Macedon coming on in the third quarter of 2013. So we've got -- we're going to see a little dip in Australia and then we're going to see a big ramp-up again.

And I guess, when we think about that ramp-up on the oil side, does that ramp-up just kind of get back to the levels that you've been producing, which has been relatively consistent for this year in the 28,000 to 30,000 barrels a day range? Or does it step up beyond that?

Well, I don't have that. I can't answer that question. I just -- and it's not that I wouldn't, I just don't have it in front of me. I don't know what our profile looks like.

And lastly, in Egypt. Can you just talk to any discussions with the government you've had since your last update? And any thoughts on royalty rates and overall government take?

Yes, I had. And in fact, both Rod and I spent a week in September in Egypt. I happen to be the Head of the U.S.-Egyptian Business Council. And we had 48 U.S. companies there, some of the largest companies in the world. We met with the president, the prime minister. I think we had government officials with us from the U.S. Quite frankly, we've been very pleased and very positive about not only that trip but our relationship with the government. Rod alluded to that we have a new Petroleum Minister, who is, frankly, a breath of fresh air. We've got more things done in the last 90 days than we got done in the last 2 years in terms of development leases approved, issues that we needed to get solved, a new gas contract at Hydra, so -- and honestly, I'm very positive about their direction, at least for our sector.

[Operator Instructions] Your next question will come from the line of Eliot Javanmardi with Capital One Southcoast.

Yes, guys, just wanted to see if you could speak to the increase in LOE for this quarter. I noticed a significant amount of it was related to repair and maintenance, and just wanted to see if that would essentially roll off for next quarter and come back down?

That will roll off next quarter. We had -- we talked about the Grand Isle 43 corrosion issue that we had. That production was off in the second quarter. That cost hit us in the third quarter, that's a onetime cost. And then we had the North Sea tire cost and some of the Canada SemCAMS plant downtime cost, turnaround costs in there as well. So those are all one-period type costs. So you should see that coming down. And with the production back up, the per boe should drop as well.

Very good. And also then in regards to exploration in Gulf of Mexico, what wells could we see just expecting to come forward then -- as far as results are concerned? Is there any left this year? Or is it in 2013? Do you have some 1Q '13?

No, it's going to be -- it'll be 2013. We don't pick up our rate until, I think, the first quarter of 2013 for our drilling, our first prospects.

In the deepwater.

In the deepwater. We have a well going right now at Heidelberg, a development well by Anadarko -- I'm sorry, Lucius, that Anadarko is drilling, but that's development drilling. So you won't see any real impact from our drilling activity in the deepwater Gulf of Mexico until next year. And we're actively drilling shelf well, Gulf of Mexico shelf wells as we speak.

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

Back to the Permian Basin. It -- kind of the Midland, parts of the [ph], I guess I'll call it the Deadwood area. What would you characterize as your best part of the basin?

Well, I'll tell you, it's hard to tell. I mean, we thought the stuff we were doing down in the -- hang on one second. I've got -- now he's going to give me a chart here. Well, actually the best results we've had so far in the individual wells is the Wolfcamp Shale, but I don't know that, if you caught -- if we drilled a well on the Central Basin platform in the Wichita Albany, those wells came on 900 barrels a day, still making about 8 -- over 600 barrels a day, both of them. And we have about 23 locations to drill in there. So the one thing I would say about the Permian Basin and the reason we started getting in there in 1991 and made a number of acquisitions before we made BP is exactly where we are today: We've got a tremendous acreage position. It is the oiliest place in North America, oiliest place in the world outside of Russia. So it has a lot potential for horizontal drilling. And I think Rod mentioned we're going from -- I don't -- we're going to drill 123 wells this year horizontal. Next year, we're -- it's going to be more like half of our wells. We're just on the cusp. Not just us, everybody is, in terms of understanding the Permian Basin and the kind of oil that's out there.

Okay. And then a follow-up. You guys talked about -- at the Analyst Day talked about some similar basin, drilling you're doing, it was 15 to 20 wells you're going to drill out there. Any comment -- and maybe I missed it in the prepared remarks, but any comment on kind of overall the results from that program and what you're seeing over there?

As I said in my prepared remarks, in the Delaware, the Yeso, in particularly [indiscernible] is our principal area outside the Central Basin Platform in the Midland Basin. The program there has been vertical up to this point, but will be turning horizontal soon. It certainly met our expectations per drill.

Okay, okay. So you're just -- you got nothing from the Avalon and Bone Spring.

No, it's -- the main part of the Delaware is the Bone Spring for you. It's a modest part of our portfolio compared to the other drilling we've been doing out in the basin.

Your next question will come from the line of Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: I was curious, is there an update you can share with us on the Mbawa well offshore Kenya and, if you have any results or indication there, what the implications might be for the [indiscernible]?

I think we've talked about it at the last conference, I mean, call. But we found gas. It had a real chance of finding gas. We thought we'd find an oil leg. We drilled on big structure, we found some gas. That's not what we were looking for. We're now reevaluating that block. We got 1 million acres there. So we're reevaluating that block. I happened to see we're too low, just drilled another oil well onshore Kenya. But we're -- this -- what we were looking for is not in the same horizon that Tullow is drilling onshore. And I think they're in the Cretaceous. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: My apologies if I missed that. And the follow-up question, going back to the Permian Basin. Are -- you mentioned there are -- you guys mentioned in your prepared remarks some good Cline results, I thought. And I wondered if you could offer your thoughts on the relevant maturity and attractiveness of the Cline horizontal play versus the Wolfcamp horizontal play.

I think Rod pointed out that well is making 600 barrels a day. So it tested -- first 30 days, I think, 600 barrels a day. And I -- and if you look at our acreage position and what we showed at the resource potential and what we're looking at now, I mean, it's different. It's bigger because what we found is just -- we drilled the Barnett Shale well in the Deadwood area. We didn't drill it that far horizontal, it's made 300 barrels a day. I'll go back to my statement from a question earlier, and that is, we -- as an industry, we haven't yet fully evaluated the most important plays in the Permian Basins. And I'll go back to the Wichita Albany. I mean, I'm shocked that the Wichita Albany is making 900 barrels a day.

Your next question will come from the line of Mario Barraza with Tuohy Brothers.

Just had a question more on the -- was it the cottage? I'm sorry.

Cottage Grove? Hello?

The activity for this level in the Granite Wash?

Well, we drilled a couple of Cottage Grove wells. Actually, more than that, I think we drilled 4. It's a very good play. The Anadarko Basin has sands from the Tonkawa all the way down to the Atoka, and as you get deeper, it gets gassier. But that's another area that we've just scratched the surface as an industry and finding things, like Hogshooter. I mean, we go down there and drill a couple of Hogshooter wells and 2 or 3 of them make 4,000 barrels a day. And I can't emphasize enough, you want to be in basins that have a lot of thickness and a lot of hydrocarbons, and we're in 2 of the best. And I will tell you, one of these days, the western sedimentary basin of Canada is going to look like this. They're just way -- they're a lot further back in terms of their learning curve and exploiting it.

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

Wanted to dig into each of the [indiscernible] a little bit more here. So if I'm looking at the numbers right, your gross oil production on a gross basis in Egypt has kind of dropped for it looks like the past 4 quarters here. That had been an area that you had grown for years and years and it's kind of reversed trend. Has that been kind of a slowdown with the transition government you talked about? Maybe getting more traction here with the new energy minister? How should we expect gross Egyptian oil production to sort of change gears [ph] again into '13?

Yes, and we're going to have to put on a little presentation. It's -- or maybe put something out. Actually, our gross production, gross operated production in Egypt is higher than it was at the beginning of the year. And our gross operated gas is higher than it was. What happens is, is that you get -- because of the way that the concession agreement works, if -- the price of crude oil has an awful lot to do with what you report for net production. So we need to start putting out our gross production and our net production because it's -- Egypt is still very good and going to continue to be good. And we're going to continue to see bumps in our net production based on oil prices.

Okay, I guess I was looking at some of those numbers in your supplement, and I guess maybe I was looking at them wrong. But I saw you did 211,000 gross barrels a day this quarter. And I saw like...

No, that’s about right. And what do we do in the quarter before, 216?

I saw 215 in the first quarter of '12 and it was, like, 220 in the third quarter of '11. So it's kind of been slowly coming down. So I wasn't sure if that was sort of a Permian issue or bottlenecks or you guys just weren't...

Yes, there's -- some of that is. I will tell you. Yes, we had a plant turnaround at Terric [ph] for the third quarter.

Okay, got you. And you mentioned getting good traction in last 90 days with the new Petroleum Minister over there. I guess, do you expect that to really kind of change things as we get into 2013 in Egypt for you?

Right. I -- we've got 26 rigs running. We -- it still gives us the highest rate of return in the company. And I don't -- that's probably what we're going to run all of next year.

Okay. I guess, looking at your gas production in Egypt, the other thing I noticed was that it looked like your net take in the third quarter was a fair bit lower, I'm seeing about 36% of the gas versus the gross. And previously, it had always kind of been 40% or higher. Is there anything in particular that happened in the third quarter? Should we expect it to stay at that kind of a 36% level going forward, or is that going to rebound? How should we think about that?

There's been no material change in the gross gas production, except for the turnaround we just mentioned. Some of this is PSC related and which Steve just mentioned. But I should point out that the value of the gas, all that gas we produce in Egypt, is only about 18% on a revenue basis compared to the value of the oil. So all the value in Egypt is coming from the oil and condensate we produce.

Our final question will come from the line of Robert Christensen with Buckingham Research.

A little bit more on the Williston Basin, if you might. Just you've got, I think, 3 permits, maybe 1 well drilled and testing. And just a little more color on that, that's question one. Question two, I've heard you've been actively leasing up there even more land. And question three, have there been any other well results by other companies that have been encouraging to you?

We are in the process, actually, of frac-ing our first well up there and we're drilling our second well. I think, yesterday, we were at 2,700 feet. So we're going to have 2 wells down by the end of the year. We're not picking up big amounts of acreage before filling into the land block that we've put together, which is -- I think is about 300,000 acres or so. And there have been some other operators, it's not right next door, that have announced pretty good results. I mean, the play is moving that way, so hopefully, it moves all our way. We're going to find out here pretty quick.

I would now turn the conference back over to Brady Parish for any closing remarks.

We just wanted to thank everybody for participating today. And have a great remaining week.

Ladies and gentlemen, this does conclude today's conference. Thank you, all, for joining. And you may now disconnect.