Nexen Touts $255MM Net Income in 2Q
Nexen announced solid financial results for the second quarter with cash flow of $558 million and net income of $255 million. We continue to achieve execution success with our three strategies and our non-core asset disposition program.
At our Long Lake oil sands project, bitumen production volumes continue to reach new highs and the upgrader is operating reliably, producing the highest quality synthetic crude in North America. In Horn River shale gas, we have started fracing the eight wells we drilled earlier this year. Our costs are coming down and we are executing our program at industry leading levels. In addition, we were successful at a recent land sale in northeast British Columbia where we more than doubled our shale gas position. On the conventional side of our business, we have had major discoveries in each of our three key conventional basins in the past 18 months-Golden Eagle area in the North Sea, Appomattox in the deep-water Gulf of Mexico and Owowo, offshore West Africa.
All our success is contributing to new production volumes, starting with approximately 70,000 bbls/d coming from Long Lake, Usan and shale gas over the next 24 months. Golden Eagle, Appomattox, Knotty Head, Owowo, shale gas and future oil sands phases will contribute to production volumes thereafter. With the recent sale of our Western Canadian heavy oil assets, we have exceeded our target of generating $1.0 billion from non-core asset sales. We have now increased our target to approximately $1.5 billion once we complete our disposition program which includes the sale of our Canexus investment.
In the Gulf of Mexico, the six month drilling moratorium has had no significant impact on us to date. It will likely delay our exploration and appraisal drilling programs but have little cash cost to us for the remainder of the six month period.
Second quarter highlights include:
- Quarterly cash flow of $558 million ($1.06/share) and net income of $255 million ($0.49/share)
- Quarterly production before royalties of 248,000 boe/d (218,000 boe/d after royalties)-impacted by Buzzard scheduled downtime
- Long Lake gross bitumen production has increased from 16,000 to 28,500 bbls/d since January-on track to exit the year at 40,000 to 60,000 bbls/d
- Successful disposition of Canadian heavy oil properties-sale closing soon realizing excellent value for non-core assets
- Annual production guidance unchanged at between 230,000 and 280,000 boe/d (200,000 and 250,000 boe/d after royalties)
- Success at British Columbia land sale-more than doubling our shale gas acreage
Quarterly cash flow from operations was $558 million and net income was $255 million. In comparison to the same quarter last year, our cash flow has increased from stronger production and commodity prices. Our net debt is down over $400 million from a year ago and will decline substantially more once we close the heavy oil sale and sell our Canexus interest.
With consistent and improving performance at Long Lake, we stopped capitalizing start up results as of December 31, 2009. Since the first quarter, our cash flow operating loss from Long Lake has decreased from $58 million to $19 million in the second quarter. Our absolute operating costs have largely remained flat and with growing volumes our unit operating costs have improved 43% over the previous quarter. When fully ramped up, we expect Long Lake's operating costs to be about $25/bbl.
"With volumes increasing steadily, Long Lake is approaching breakeven and we expect to generate positive cash flow later this year," stated Marvin Romanow, Nexen's President and Chief Executive Officer. "This will be an important milestone and shows the future cash generating ability of Long Lake as we continue to ramp up to design rates."
Second quarter production volumes were 85% weighted to crude oil and averaged 248,000 boe/d (218,000 boe/d after royalties) due to scheduled downtime at Buzzard in the North Sea. Buzzard's production averaged 165,000 boe/d gross (71,000 boe/d net to us) compared to typical rates of approximately 210,000 boe/d gross (90,000 boe/d net to us). Production here was reduced for approximately three weeks while we installed the fourth platform topsides and successfully repaired the main separator unit. Production from our Ettrick field more than doubled over the prior quarter and averaged 14,000 boe/d net to us. Ettrick is currently producing at approximately 20,000 boe/d net to us and continues to ramp up.
Earlier this week, a valve failure on the Forties pipeline system required us to shut-in our production from the Scott platform. The operator is currently determining the root cause and the nature of the repairs. While the operator undertakes this work, we are advancing our shutdown at Scott that was planned for later this summer. Second quarter production rates from our Scott/Telford fields averaged 18,000 boe/d.
At Long Lake, our quarterly bitumen volumes continue to grow following the successful completion of the turnaround last fall. Long Lake's gross bitumen production has increased from 14,000 bbls/d in the fourth quarter of 2009 to 19,000 bbls/d in the first quarter of 2010 to 25,000 bbls/d in the second quarter. This represents a growth rate of over 30% each quarter as we are seeing production increases from new wells and optimization of mature producers. We are currently producing approximately 28,500 bbls/d and are on track to exit the year between 40,000 and 60,000 bbls/d gross. We have a 65% operated working interest in the project.
At Syncrude, production returned to normal levels following a turnaround of the LC finer in the first quarter. A coker turnaround is scheduled at Syncrude in the third quarter.
"As we grow production at Long Lake, Ettrick and in the Horn River, we are on track to meet our original production guidance even after the sale of our heavy oil assets," stated Romanow.
Non-Core Asset Sales Update-Heavy Oil Disposition Realizes Exceptional Value
As previously announced, we signed an agreement to sell our heavy oil properties in Western Canada for approximately $975 million (before closing adjustments and costs). The sale is expected to close shortly. These properties produced approximately 15,000 boe/d in the second quarter and had proved reserves of 39 million boe at December 31, 2009.
During the quarter, we signed an agreement to sell our North American natural gas marketing business. The transaction is expected to close in the third quarter subject to customary closing conditions. The terms of the agreement transfer substantially all related market risk to the buyer effective May 5, 2010.
"We have achieved excellent value on the sale of our non-core assets, met our target of $1.0 billion of proceeds and expect to generate total net gains of approximately $500 million," said Romanow. "We now expect over $1.5 billion from all asset sales, once we complete our disposition program which includes the sale of our interest in Canexus over the next 12 to 18 months. The proceeds will be used to develop the exciting success we are having with our conventional exploration, oil sands and shale gas assets."
Long Lake-Upgrader Performing Well and Bitumen Production Continues to Increase
The upgrader is performing well and is consistently processing virtually all of our bitumen production as well as 9,000 bbls/d of purchased bitumen. The gasification process is working, creating a low-cost fuel source which reduces our need to purchase natural gas for operations and will generate a significant margin advantage over our peers, even at current low gas prices.
Bitumen production to feed the upgrader continues to ramp up following the completion of the turnaround last fall as we have significantly improved steam reliability and are optimizing our wells. Steam rates have more than doubled from pre-turnaround levels and we are currently at all-time highs of about 150,000 bbls/d. As a result, we are injecting more steam into more wells than ever before with 68 of 91 well pairs now on production and steam circulating in an additional 13 pairs. These circulating wells will be converted to production over the next few months.
As we provide consistent steam to the reservoir, we are focusing on optimizing steam injection and individual well performance. To support increased well productivity, we have converted 54 wells from gas lift to electric submersible pumping and will convert the remainder, when appropriate. This offers more flexibility to optimize steam injection and grow bitumen production.
Our all-in steam-to-oil ratio (SOR) is between 5 and 6 and includes steam to wells that are still in the steam circulation stage and wells early in their growth cycle. As our circulating wells start producing bitumen, we expect to see an increase in production rates with a corresponding decrease in SOR. The SOR of our mature producing wells is now 4 and improving.
We continue to pursue inexpensive ways to add bitumen capacity since bitumen production in excess of upgrader capacity can be sold for an attractive return. As a result, we are continuing with the development of two additional well pads and have commenced engineering work to add two more once-through steam generators over the next 18 to 24 months. These steam generators can be added for a cost of about $100 million ($150 million gross).
"For a modest investment of less than 3% of total project capital, we have the opportunity to increase our steam capacity by 10 to 15%," said Romanow. "This additional capacity, combined with the two new well pads which add 20% to our existing well count starting in 2012, positions us well to be bitumen long."
Phase 1 of our Long Lake project is designed to produce 72,000 bbls/d of gross bitumen, upgraded to approximately 60,000 bbls/d (39,000 bbls/d, net to us) of PSCTM and will develop approximately 10% of our oil sands inventory. We are committed to the development of our oil sands leases and plan to develop Phase 2 in two smaller SAGD stages of about 40,000 bbls/d each with upgrading available after ramp up.
"Developing Phase 2 in smaller stages will result in better management of capital investment and reduce stress on material, equipment and labor markets," commented Romanow.
Global Exploration-No Material Impact from Drilling Moratorium in the Gulf
The six month drilling moratorium in the Gulf of Mexico has no material impact on our current operations. Our shelf and deep-water production are unaffected and we continue to expect our Gulf of Mexico production for the year to average between 20,000 and 28,000 boe/d before royalties (17,000 and 25,000 boe/d after royalties).
At Knotty Head, we completed drilling an appraisal well before the moratorium. We are currently evaluating results, considering possible development choices and continuing our efforts to unitize our lands with adjacent acreage. No other drilling was planned in the near term. We are the operator of Knotty Head with a 25% working interest.
In the first quarter, we made a significant discovery in the deep-water at Appomattox, located in Mississippi Canyon blocks 391 and 392. This has the potential to be our best discovery in the Gulf of Mexico. Drilling activities resulted in a light oil discovery with excellent reservoir quality, following an exploration well and two appraisal sidetracks. Appomattox is the third discovery in the area following earlier discoveries at Shiloh and Vicksburg. Additional appraisal wells for Appomattox were being considered for later in the year but have been delayed as a result of the drilling moratorium. We continue to investigate development options for Appomattox and Vicksburg, located six miles east. We have a 25% interest in Vicksburg and a 20% interest in Appomattox and Shiloh. Shell Offshore Inc. operates all three discoveries.
Our plans to drill two additional exploration wells later this year with two new deep-water drilling rigs have been delayed by the drilling moratorium. The first deep-water rig, the Ensco 8501, completed drilling an appraisal well at Knotty Head and is currently being used by the third party we share the rig with. The second rig, the Ensco 8502, has arrived in the Gulf and is undergoing sea trials prior to its acceptance. The drilling moratorium and new regulations may delay rig acceptance.
"Although the moratorium has delayed our exploration program and the delineation of our discoveries, the timing impact of delays is not material as these are long-cycle time projects," commented Romanow. "To date, the moratorium has not resulted in any cash costs and for the remainder of the six month period, we expect our costs to be modest, if anything."
During the quarter, we completed drilling a successful appraisal well at our Blackbird discovery, a potential tie-back to Ettrick. The well was drilled in a water depth of approximately 367 feet to a total measured depth of 12,000 feet and encountered light sweet oil in good quality Upper Jurassic reservoir sands. We are currently acquiring extensive wireline log and core data over the reservoir section for further analysis. Preliminary analysis suggests the well encountered a gross oil bearing section of approximately 330 feet, with a minimum net oil pay of approximately 75 feet. We plan to complete the well and drill stem test later this month. If successful, the well will be suspended for future use as an oil producer. We have a 79.73% operated interest here.
Elsewhere in the North Sea, the Golden Eagle area is a significant development opportunity for us. Our current estimate of recoverable contingent resource is 150 million boe or higher (over 55 million boe, net to us). We are in the process of completing the acquisition of additional acreage in the area and plan to drill an exploration well here later this year. Golden Eagle area development supports standalone facilities and is economic with oil prices significantly lower than they are currently. We are assessing development options for the area and will select an appropriate configuration for sanctioning in 2011. We have a 34% interest in both Golden Eagle and Hobby, a 46% interest in Pink, and operate all three.
At Buzzard, we have a number of opportunities to add reserves. In the northern part of the field, we are seeing more oil above the water contact which will lead to more recoverable oil. In the south, we plan to drill Bluebell, a possible extension of the Buzzard field. At Polecat, a previous discovery east of Buzzard, we plan to drill an appraisal well which could be tied back to the Buzzard platform.
West of the Shetland Islands, we are finalizing plans to drill the North Uist prospect. We have a 35% non-operated working interest here and expect to drill the well later this year. This prospect has a target size much larger than typical North Sea targets.
Conventional Development-Usan Development Continues
Offshore West Africa
Development of the Usan field is progressing well with first production expected in 2012. The development includes a floating production and storage offloading (FPSO) vessel with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. In June, major topside modules were lifted onto the FPSO deck and the FPSO unit is almost 80% complete. We have a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.
We continue to explore offshore West Africa and previously announced a successful exploration well at Owowo in the southern portion of Oil Prospecting License (OPL) 223. We have an 18% interest in this discovery.
"Usan is a significant step-change in our production growth, adding 36,000 boe/d of the 70,000 boe/d that we expect to bring on stream over the next two years," stated Romanow. "As we move forward here, our success at Owowo makes us more optimistic about other exploration prospects."
Shale Gas-Fracing Eight-Well Program and Successful Land Acquisition
In the first quarter, we completed drilling our eight-well program in the Horn River and realized substantial cost savings and productivity improvements. Our average drilling days per well were under 25 days, down 35% from our previous program while drilling 80% more reservoir length. We recently began fracing these wells and plan to conduct 18 fracs per well. First production is expected before year end, ramping up to 50 mmcf/d in early 2011.
"Horn River is a top-tier gas play where we are successfully executing our plans and bringing unit costs down," commented Romanow. "Based on what we know today, this play is expected to earn a ten percent rate of return with gas prices at US$4/mcf."
As previously announced, we have approximately 90,000 acres at Dilly Creek in the Horn River basin and 38,000 acres at Cordova. Our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource, assuming a 20% recovery factor. Following our success at a June land sale, we have increased our position from 128,000 to over 300,000 acres of highly prospective shale gas lands in northeast British Columbia.
"With this acquisition, we are now one of the largest shale gas players in the area," said Romanow. "We are excited about these lands given their significant resource potential, the excellent land tenure terms and the good rocks. The lands contain plays that are similar to those on our Horn River lands, where we are having great success."
Yemen is an important asset for us and continues to generate cash flow in excess of capital requirements. In December 2011, our production sharing contract with the Yemen government expires. We are currently working on a possible contract extension.
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable October 1, 2010, to shareholders of record on September 10, 2010. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.
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