News & Analysis
Nexen Announces Solid Financial Results & Progress on Milestones
Nexen Inc. (TSX, NYSE: NXY) today reported 2011 fourth quarter and annual operating and financial results, and provided a progress update on its strategic priorities for 2012.
In the fourth quarter, we generated cash flow from operations of $585 million ($1.11/share), reflecting a 12% increase in production over the third quarter to 208,000 boe/d (193,000 boe/d after royalties), and cash netbacks from oil and gas operations of $42.85/boe (after-tax).
Net income was $43 million ($0.08/share), reflecting one-time, after-tax charges of $190 million ($0.36/share) related to previous costs associated with our shift away from large, integrated upgrading projects in our future oil sands development strategy, and $127 million after-tax ($0.24/share) for impairments related to our gas assets in Canada and the United States, due to low gas prices.
For the full year, cash flow was $2.4 billion ($4.49/share), net income was $697 million ($1.32/share) and production averaged 207,000 boe/d (186,000 boe/d after royalties). Cash netbacks from oil and gas operations were $40.20/boe (after-tax) in 2011.
The annual results met our expectations for cash flow ($2.1-$2.8 billion) and our revised expectations for production (200,000-215,000 boe/d). Total 2011 capital expenditures of $2.6 billion were also within our expected range of $2.4-$2.7 billion.
"Nexen delivered solid results in the fourth quarter," said Kevin Reinhart, Nexen's interim President & CEO. "Production met expectations, Long Lake generated positive cash flow, and we entered into two joint ventures in the Gulf of Mexico and shale gas with strong partners.
"I'm pleased with the commitment our employees have made to delivering on our strategic priorities for 2012 and beyond," continued Reinhart. "2012 has started off strong. Long Lake production continues to grow and Buzzard is back to operating normally. We advanced our near term production growth projects including Usan, our UK tiebacks and Long Lake pads 12 and 13. We are also excited about our second drilling success on the Appomattox field in the Gulf of Mexico."
Fourth Quarter Overview
-- Cash flow from operations of $585 million ($1.11/share).
-- Net income of $43 million ($0.08/share); reflects $190 million
($0.36/share) after-tax charge related to future oil sands projects and
$127 million ($0.24/share) of after-tax impairments on gas assets in
Canada and the US.
-- Production of 208,000 boe/d (193,000 boe/d after royalties).
-- Cash netback from oil & gas operations of $42.85/boe, after-tax.
-- Long Lake cash flow of $22 million, driven by higher production and
improving yield; this resulted in positive cash flow of $5 million for
the full year.
-- Buzzard production of 186,000 boe/d (80,000 boe/d net to Nexen).
-- Achieved first production from Blackbird tieback in the UK.
-- Started up our 9-well shale gas pad in northeast British Columbia.
-- $700 million joint venture (JV) agreement on northeast British Columbia
shale gas assets, representing a 60% premium to our invested costs;
closing in the first half of 2012.
-- JV agreement on up to six exploration wells in the Gulf of Mexico; deal
completed on a promoted basis and has closed.
2011 Overview
-- Cash flow from operations of $2.4 billion ($4.49/share).
-- Net income of $697 million ($1.32/share).
-- Production of 207,000 boe/d (186,000 boe/d after royalties).
-- Cash netback from oil & gas operations of $40.20/boe, after-tax.
-- Proved reserve additions replacing 96% of production.
-- Strategic transactions: disposed of our interest in Canexus for $458
million (net) and signed JV agreements in northeast British Columbia and
the Gulf of Mexico.
-- Supported CNOOC Limited's acquisition of our partner at Long Lake, OPTI
Canada; CNOOC brings technical and financial capacity to the
partnership.
-- Continued to reduce net debt using proceeds from non-core asset
dispositions.
-- Sanctioned and began construction on the Golden Eagle and Rochelle
developments in the UK North Sea.
-- Developed and commenced action plan to increase production at Long Lake
to fill the upgrader: ramped-up pad 11, drilled pads 12 and 13 and
progressed regulatory process for pads 14, 15 and Kinosis K1A.
-- Commissioned the fourth platform at Buzzard and it is now operating
normally.
2012 Update
-- On track to meet 2012 first quarter production guidance.
-- At Appomattox, we completed drilling in the northeast fault block of
the structure and have confirmed an oil discovery; this followed a
previous success in the south fault block.
-- Usan project in Nigeria on track for start-up; Usan drives 2012 cash
margin expansion.
-- Long Lake bitumen production as of early February approximately 35,000
bbls/d.
-- Long Lake pad 12 and 13 drilling is complete and results met our
expectations; pad 12 on track for first steam this spring, pad 13 to
follow.
-- Telford TAC tieback in the UK North Sea came on-stream in February.
Results Summary
Three Months Ended Year Ended
----------------------------------------------------------------------------
(Cdn$ millions Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
unless noted) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Brent
(US$/bbl) 109.31 113.47 86.48 111.28 79.47
WTI (US$/bbl) 94.06 89.76 85.12 95.12 79.52
NYMEX natural
gas
(US$/mmbtu) 3.48 4.06 3.97 4.03 4.39
Cash netback
($/boe)(1) 42.85 38.67 35.87 40.20 33.26
Average Daily
Production
(mboe/d)
Before
Royalties 208 186 246 207 246
After
Royalties 193 164 227 186 220
Cash flow from
operations(2) 585 516 556 2,368 2,150
Per common
share
($/share) 1.11 0.98 1.06 4.49 4.10
Net income 43 200 160 697 1,127
Per common
share
($/share) 0.08 0.38 0.30 1.32 2.15
Capital
investment(3) 817 729 685 2,575 2,724
Net debt(4) 3,538 3,454 4,085 3,538 4,085
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1. Cash netback is defined as our corporate average cash netback from oil
and gas operations, after-tax.
2. For reconciliation of this non-GAAP measure, see Cash Flow from
Operations on pg. 13
3. Includes geological and geophysical expenditures.
4. Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
Fourth quarter cash flow from operations increased 13% over the third quarter primarily due to increased production and our rising cash netbacks. Annual cash flow from operations was the highest since 2008 as our weighting to unhedged, Brent-priced oil allowed us to realize premium pricing throughout the year. Brent averaged US$111 in 2011; this represented a $16 premium to WTI.
Net income declined quarter-over-quarter and year-over-year as a result of several items. It reflects a one-time charge of $190 million (after-tax) related to changes in our future oil sands development strategy. Our original strategy was to build duplicates of the existing Long Lake SAGD facilities and upgrader. We now expect to pursue smaller, phased, SAGD-only projects and will consider adding upgrading capacity once we are bitumen-long and economic conditions are favourable. As a result, previously capitalized design and engineering work done on the future phases has been expensed.
Lower annual net income also reflects impairments, primarily on our gas assets, in the third and fourth quarters of 2011, and gains on the sale of our heavy oil properties which increased net income in the third quarter of 2010.
Net debt has declined 13% in the past year and 36% over the past two years based on the success of our non-core asset disposition program.
Production Summary
Average Daily Quarterly Average Daily Quarterly
Production before Royalties Production after Royalties
Crude Oil, NGLs
and Natural Gas
(mboe/d) Q4 2011 Q3 2011 Q4 2010 Q4 2011 Q3 2011 Q4 2010
----------------------------------------------------------------------------
North Sea 102 71 115 102 71 115
Yemen 27 32 40 16 17 23
United States 18 21 27 18 19 28
Canada - Oil &
Gas 20 19 21 20 17 20
Canada -
Syncrude 18 22 23 16 21 21
Canada - Bitumen 21 19 18 19 17 18
Other Countries 2 2 2 2 2 2
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Total 208 186 246 193 164 227
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Fourth quarter production increased 12% over the third quarter, primarily due to higher production from Buzzard and Long Lake.
Reliability at Buzzard significantly improved following completion of the commissioning of the fourth platform; our production efficiency rate was 86%. For 2012, we are targeting 85% before planned shutdowns (78% including scheduled downtime).
In the North Sea, the Blackbird tieback to Ettrick came on-stream in November, seven weeks ahead of schedule, and is currently producing to expectations; production in the fourth quarter was approximately 5,000 boe/d (gross). Severe weather resulted in longer than expected downtime to complete the Telford TAC tieback, which was finished in early February.
Long Lake bitumen production averaged 31,500 bbls/d (gross). This represents a 7% increase over the third quarter as production from the first 11 pads continues to increase and facility turnarounds were completed in the third quarter. At Syncrude, production was lower as a result of unscheduled maintenance on a hydrogen plant.
Production in Yemen and the Gulf of Mexico continued to experience natural declines; Yemen production was further reduced with the expiry of our contract for the Masila block in mid-December.
Annual Production before Annual Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) 2011 2010 2011 2010
----------------------------------------------------------------------------
North Sea 90 111 90 111
Yemen 33 41 18 23
United States 22 27 21 25
Canada - Oil & Gas(1) 20 28 19 25
Canada - Syncrude 21 21 19 19
Canada - Bitumen 19 16 17 15
Other Countries 2 2 2 2
----------------------------------------------------
Total 207 246 186 220
----------------------------------------------------
1. 2010 includes production before royalties of 9 mboe/d and production
after royalties of 7 mboe/d from discontinued operations.
Production in 2011 was lower than 2010, primarily as a result of the sale of our heavy oil properties in the third quarter of 2010, natural declines, and production interruptions at Buzzard due to unplanned maintenance, third-party pipeline restrictions, and delays in commissioning the fourth platform.
We met our revised fourth quarter and annual production guidance.
Average Daily Quarterly Average Daily Annual
Production before Production before
Royalties Royalties
Crude Oil, NGLs and Q4 2011 FY 2011
Natural Gas (mboe/d) (prior Q4 2011 (prior FY 2011
estimate) (actual) estimate) (actual)
----------------------------------------------------------------------------
Buzzard 75 - 95 80 61 - 66 62
Other UK 24 - 32 22 28 - 30 28
Yemen 24 - 33 27 32 - 35 33
United States 21 - 24 18 23 - 24 22
Canada - Oil & Gas 19 - 22 20 20 - 21 20
Canada - Syncrude 20 - 23 18 21 - 22 21
Canada - Bitumen 18 - 24 21 18 - 20 19
Other Countries 2 2 2 2
----------------------------------------------------
Total approx. 200 approx. 200
- 230 208 - 215 207
----------------------------------------------------
----------------------------------------------------
Guidance Update
We are on track to achieve 2012 first quarter production guidance. Year-to-date production volumes are a little over 190,000 boe/d compared to our first quarter guidance range of 180,000-220,000 boe/d.
Buzzard has averaged approximately 185,000 boe/d (gross) so far this year, reflecting our operating efficiency of 85%. At Long Lake, bitumen production has increased to recent 7-day rates of approximately 35,000 bbls/d as pad 11 production continues to grow and we focus on production optimization from all wells.
At Long Lake, we have rescheduled the planned maintenance turnaround to take advantage of better labour availability. As a result, the three-week SAGD turnaround and six-week upgrader outage will now take place in the third quarter; they were previously scheduled for the second quarter. We have updated our second and third quarter guidance to reflect this change in timing.
Estimated Average Daily Production before Royalties
Crude Oil, NGLs and
Natural Gas
(mboe/d) Q1 2012 Q2 2012 Q3 2012 Q4 2012 2012 Annual
----------------------------------------------------------------------------
Buzzard 75-95 75-95 50-60 75-95 70 - 85
Other UK 26-34 26-34 20-26 25-32 24 - 32
Canada - Syncrude 22-24 18-20 22-24 22-24 21 - 23
Canada - Bitumen 20-25 20-27 14-18 22-28 19 - 25
West Africa 0-10 13-30 20-35 22-35 14 - 28
United States 15-20 15-20 13-17 15-17 15 - 19
Canada - Oil & Gas 15-20 15-18 15-17 15-20 15 - 19
Other Countries 2 2 2 2 2
--------------------------------------------------------
approx. approx. approx. approx. approx.
180 - 220 190 - 235 160 - 190 205 - 240 185 - 220
--------------------------------------------------------
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Operational Update
Conventional
Offshore West Africa - Development of the Usan field remains on schedule; the project is our largest source of new production in 2012 and is expected to contribute to significantly stronger corporate cash netbacks this year. Final commissioning activities are in progress and first production is expected in the next month or two. Development activities were not affected by earlier civil unrest in Nigeria.
Usan's facility capacity is 36,000 bbls/d net to Nexen; actual production rates will vary based on well performance, pace of ramp-up and facility uptime.
"First production from Usan will be a major achievement," commented Reinhart. "The project is our newest legacy asset, and will generate significant cash flow for Nexen for many years. It also significantly strengthens our corporate netback, as the margin it generates is higher than our already strong corporate average."
We expect to drill an exploration well at Owowo West in 2012. This well is targeted to follow-up on our earlier success at Owowo South B.
UK North Sea - Following final regulatory approval of the Golden Eagle development early in the fourth quarter, we began work on the fabrication of the facilities, utilizing many of the same teams that oversaw the successful construction of the Buzzard platforms. The work is proceeding on-time and on-budget, and we expect first production in late 2014. The facility will have a capacity of 70,000 boe/d (26,000 boe/d net to Nexen).
We also continue to progress our tieback projects in the North Sea. Blackbird came on-stream through the Ettrick facility in November and is currently producing to expectations. Telford TAC came on-stream in February; Rochelle is proceeding as planned and first production is expected around the end of 2012.
We have an active UK exploration program planned, including the North Uist exploration well west of the Shetland Islands, where drilling is expected to begin late in the first quarter.
Gulf of Mexico - At Appomattox, we followed-up our successful 2010 exploration well in the south fault block with another success in the northeast fault block. The well encountered approximately 150 feet of net oil pay; we are currently completing an evaluation to determine the size of the discovery. Resource on the northeast block would be in addition to the 65 million boe of probable reserves we booked on the south block.
We plan to continue drilling at Appomattox with an appraisal well on the south fault block and a sidetrack into the northwest fault block to test the third major part of the Appomattox structure. We have a 20% interest in Appomattox, the remaining interest is held by Shell Offshore Inc., who is the operator.
At Kakuna, we expect to reach target depth around the end of the first quarter. We expect to drill our next operated exploration well in the Gulf, at Angel Fire, later this year.
Oil Sands
Long Lake - At Long Lake, our focus is on advancing the 60 additional wells to fill the upgrader.
In the fourth quarter, Long Lake showed strong progress. Total production increased 7% over the prior quarter to 31,500 bbls/d of gross bitumen at a steam oil ratio (SOR) of 4.8.
Upgrader yield (PSC(TM) barrels per barrel of bitumen) was 76% and facility on-stream time was 78%. Per barrel operating costs were lower than previous quarters, primarily due to the increased production and the higher yield.
These factors contributed to positive cash flow from operations of $22 million in the quarter and $5 million for the full year.
Long Lake Quarterly Operating Metrics
Bitumen Steam Unit
Production Injection Operating Realized
(Gross) (Gross) Cost(1) Cash Flow Price
(bbls/d) (bbls/d) ($/bbl)($ millions) ($/bbl)
----------------------------------------------------------------------------
2011
Q4 31,500 151,000 67 22 97
Q3 29,500 144,000 85 (4) 94
Q2 27,900 152,000 95 6 109
Q1 25,500 146,000 89 (19) 90
2010
Q4 28,100 158,000 86 (9) 83
Q3 25,700 146,000 85 (42) 71
Q2 24,900 137,000 90 (19) 74
Q1 18,700 114,000 154 (58) 81
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1. Unit operating costs and realized prices are based on PSC(TM) and bitumen volumes sold and exclude activities related to third-party bitumen purchased, processed and sold. Unit operating cost includes energy cost.
Over the past few weeks, production at Long Lake has increased to approximately 35,000 bbls/d. This reflects successful and ongoing well optimization initiatives and the growth in pad 11 production. Pad 11 is currently producing approximately 4,500 bbls/d and is continuing to ramp-up. The expected production range for this pad is 4,000 to 8,000 bbls/d.
We are making steady progress on our plans to fill the upgrader. Drilling has concluded on pads 12 and 13, and well completion activities are underway. We remain on track to begin steaming pad 12 in the spring; pad 13 is expected to follow sometime in the late summer or early fall. Production from both pads is expected before the end of the year. These pads specifically targeted higher-quality resource; our drilling results confirm that the resource quality is as we expected.
The regulatory approvals for pads 14, 15 and K1A are progressing. We are awaiting approvals for one or both projects this spring, which would enable us to begin drilling next winter. These wells have geological characteristics similar to our current best-producing wells.
In aggregate, we anticipate these wells will allow us to fill the upgrader over the next several years:
Number of Wells Expected Rates
bbls/d
----------------------------------------------------------------------------
Pad 11 10 4,000 - 8,000
Pads 12 & 13 18 11,000 - 17,000
Pads 14 & 15 10-12 6,000 - 9,000
Kinosis K1A 25-30 15,000 - 25,000
"I am pleased with the progress we are making on our action plan to fill the upgrader," said Reinhart. "We continue to increase production from our existing wells, and are on track to bring on-stream additional wells in the high-quality resource areas."
We are also continuing work on a non-operated SAGD project at Hangingstone, of which we own 25%. The operator has delayed sanctioning of the project until late this year in order to complete the regulatory approval process. We expect the project to come on-stream in 2016 and our share of production at full rates will be about 6,000 bbls/d.
Shale Gas
Northeast British Columbia - We continued our strong execution on our Horn River shale gas program during the quarter. Our 9-well pad started up ahead of schedule and early production results are meeting expectations. Preliminary results indicate initial rates up to 18 mmcf/d per well. We are currently producing at our facility capacity of 50 mmcf/d.
Work continues on our 18-well pad and we remain on-time and on-budget. We anticipate production from this pad will begin in the fourth quarter, in conjunction with an increase in our facility capacity. This is expected to bring our total gross production capacity to 175 mmcf/d.
Our previously announced JV agreement with INPEX CORPORATION and JGC Corporation is expected to close in the second quarter 2012.
2011 Capital Investment and Reserves
In 2011, we invested $2.5 billion in oil and gas activities and added 73 million boe of proved reserves. These reserve additions replaced 96% of our production. On a proved plus probable basis, reserves increased 8%. Detailed tables outlining changes to reserves can be found on page 12 of this release.
2011 Annual Results
Capital Proved Reserve
Investment Production Additions
($ millions) (mmboe) (mmboe)
----------------------------------------------------------------------------
Conventional Oil & Gas 1,525 59 25
Oil Sands 521 14 18
Shale Gas 470 3 30
---------------------------------------------
Total Oil and Gas 2,516 76 73
---------------------------------------------
---------------------------------------------
The proved reserve additions relate primarily to the following areas:
-- Northeast British Columbia shale gas (30 million boe).
-- Buzzard (15 million boe).
-- Long Lake/Kinosis K1A (10 million boe), reflecting a reduction relating
to the lower resource quality areas on Long Lake (84 million boe) more
than offset by additions from the high-quality resource in the K1A area
(94 million boe).
-- Scott/Telford, including the Telford TAC tieback (9 million boe).
-- Syncrude (8 million boe).
We have 1 billion boe of proved reserves and 2.3 billion boe of proved plus probable reserves, representing reserve life indices of 13 years on a proved basis and 30 years on a proved plus probable basis. As previously disclosed, we also have a large inventory of attractive exploration prospects and billions of barrels of oil equivalent in contingent oil sands and shale gas resources. This provides a significant resource base for future growth.
Update on Executive Appointments
Nexen also announced today that Catherine Hughes, Executive Vice President of International, and Alan O'Brien, Senior Vice President, General Counsel & Secretary, have been confirmed in their current roles; both positions were previously held on an interim basis. Una Power, Nexen's Senior Vice President of Corporate Planning & Business Development, has been appointed interim CFO; she also retains oversight for her previous responsibilities. Biographies of Nexen's senior management team are available at www.nexeninc.com.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable April 1st, 2012, to shareholders of record on March 9th, 2012.
About Nexen
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. Nexen is focused on three growth strategies: oil sands and shale gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deepwater Gulf of Mexico. Nexen adds value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.
For further information on our shale gas joint venture, please refer to our press release dated November 29th, 2011. For more information on our estimates of reserves, please refer to our Annual Information Form. For more information on our estimates of resource, please refer to our press release dated November 15th, 2010.
Conference Call
Kevin Reinhart, Interim President & CEO, and Una Power, Interim CFO and Senior Vice President of Corporate Planning & Business Development, will discuss the financial and operating results as well as Nexen's business strategy and future expectations.
The webcast will be archived under the Investors section of our website.
Conference Call Details: Date: February 16th, 2012 Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time) To listen to the conference call, please call one of the following: (416) 340-2218 (Toronto) (866) 226-1793 (North American toll-free) (800) 9559-6849 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, February 16th by calling (905) 694-9451 (Toronto) or (800) 408-3053 (toll-free) passcode 2188506 followed by the pound sign.
Forward-Looking Statements
Certain statements in this release constitute "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook", "forecast" or other similar words and include statements relating to or associated with individual wells, regions or projects.
Any statements as to possible future crude oil, natural gas or chemicals prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our operations; the expected timing and associated production impact of facilities turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs, future cost recovery oil revenues from our Yemen operations; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and our ability to comply therewith; dates by which certain areas will be developed, come on stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
All of the forward-looking statements in this release are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deepwater activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, counterparties, contractors, and joint venture parties; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on our assessment of all information at that time. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to the Risk Factors contained in our 2010 Annual Information form, and to the Quantitative Disclosures about Market Risk and our Forward Looking Statements contained in our 2010 Management Discussion and Analysis.
Note to Investors on Reserves
The reserves estimates in this disclosure were prepared in February 2012 with an effective date of December 31, 2011. The estimates of reserves and future net revenue and have been internally prepared by an internal qualified reserves evaluator in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Nexen's estimates of reserves prepared in accordance with SEC requirements are attached to its 2011 Annual Information Form.
Investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with NI 51-101 and those prepared in accordance with SEC requirements:
-- SEC reserves estimates are based upon different reserves definitions and
are prepared in accordance with generally recognized industry practices
in the U.S. whereas NI 51-101 reserves are based on definitions and
standards promulgated by the COGE Handbook and generally recognized
industry practices in Canada;
-- SEC reserves definitions differ from NI 51-101 in areas such as the use
of reliable technology, areal extent around a drilled location,
quantities below the lowest known oil and quantities across an undrilled
fault block;
-- the SEC mandates disclosure of proved reserves and the Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein
calculated using the year's monthly average prices and costs held
constant whereas NI 51-101 requires disclosure of reserves and related
future net revenues using forecast prices and costs;
-- the SEC mandates disclosure of reserves by geographic area whereas NI
51-101 requires disclosure of reserves by additional categories and
product types;
-- the SEC does not require the disclosure of future net revenue of proved
and proved plus probable reserves using forecast pricing at various
discount rates;
-- the SEC requires future development costs to be estimated using existing
conditions held constant, whereas NI 51-101 requires estimation using
forecast conditions;
-- the SEC does not require the validation of reserves estimates by
independent qualified reserves evaluators or auditors, whereas, without
an exemption noted below, NI 51-101 requires issuers to engage such
evaluators or auditors to evaluate, audit or review reserves and related
future net revenue attributable to those reserves; and
-- the SEC does not allow proved and probable reserves to be aggregated
whereas NI 51-101 requires issuers to make such aggregation.
The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material for certain properties. Please also note:
-- we use oil equivalents (boe) to express quantities of natural gas and
crude oil in a common unit. A conversion ratio of 6 mcf of natural gas
to 1 barrel of oil is used. Boe may be misleading, particularly if used
in isolation. The conversion ratio is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. Using the forecast prices
applied to our reserves estimates, the boe conversion ratio based on
wellhead value is approximately 30 mcf: 1 bbl; and
-- because reserves data are based on judgments regarding future events
actual results will vary and the variations may be material. Variations
as a result of future events are expected to be consistent with the fact
that reserves are categorized according to the probability of their
recovery.
Nexen has received an exemption from NI 51-101 that permits us to forego the requirement to have our NI 51-101 reserves and related future net revenue attributable to our reserves evaluated, audited or reviewed by an independent qualified reserves evaluator or auditor. Accordingly, our future net revenue and reserves estimates are based on internal evaluations. Due to the extent and expertise of our internal reserves evaluation resources, our staff's familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated reserves estimates is not materially less than would be generated by an independent reserves evaluator.
NI 51-101 Reserves (before royalties, forecast pricing) - December 31, 2011
Other
North Sea Intl (1) United States
---------------------------------------------
(mmboe) Oil Gas Oil Oil Gas
----------------------------------------------------------------------------
PROVED
December 31, 2010 195 11 55 19 22
Discoveries - - - - -
Extensions & Improved Recovery 1 1 1 - -
Acquisitions - - - - -
Revisions 27 1 1 - 1
Divestments - - - - -
---------------------------------------------
Net Additions 28 2 2 - 1
Production (32) (2) (14) (3) (5)
----------------------------------------------------------------------------
December 31, 2011 191 11 43 16 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROBABLE
December 31, 2010 106 10 41 7 13
Discoveries 3 - - 58 6
Extensions & Improved Recovery - - 4 1 1
Acquisitions - - - - -
Revisions 10 (1) (4) - (1)
Divestments - - - - -
---------------------------------------------
Net Additions 13 (1) - 59 6
Conversions (3) (21) (2) (2) (1) (2)
Reclassification to Bitumen (4) - - - - -
----------------------------------------------------------------------------
December 31, 2011 98 7 39 65 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROVED + PROBABLE
December 31, 2010 301 21 96 26 35
Discoveries 3 - - 58 6
Extensions & Improved Recovery 1 1 5 1 1
Acquisitions - - - - -
Revisions 37 - (3) - -
Divestments - - - - -
---------------------------------------------
Net Additions 41 1 2 59 7
Conversions (3) (21) (2) (2) (1) (2)
Reclassification to Bitumen (4) - - - - -
Production (32) (2) (14) (3) (5)
----------------------------------------------------------------------------
December 31, 2011 289 18 82 81 35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NI 51-101 Reserves (before royalties, forecast pricing) - December 31, 2011
Canada
-----------------------------------
Oil Sand Oil Sand
Gas Insitu Insitu Syncrude Total
---------------------------------------------
Bitumen Synthetic Synthetic Oil and
(mmboe) Gas (2) Oil Oil Gas
----------------------------------------------------------------------------
PROVED
December 31, 2010 71 - 314 324 1,011
Discoveries 7 - - - 7
Extensions & Improved Recovery 16 - 94 8 121
Acquisitions - - - - -
Revisions (1) - (84) - (55)
Divestments - - - - -
---------------------------------------------
Net Additions 22 - 10 8 73
-
Production (7) - (5) (8) (76)
----------------------------------------------------------------------------
December 31, 2011 86 - 319 324 1,008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROBABLE
December 31, 2010 18 - 882 46 1,123
Discoveries 29 49 - - 145
Extensions & Improved Recovery 83 - - 8 97
Acquisitions - - - - -
Revisions 4 - (40) - (32)
Divestments - - - - -
---------------------------------------------
Net Additions 116 49 (40) 8 210
Conversions (3) - - (94) (8) (130)
Reclassification to Bitumen (4) - 612 (517) - 95
----------------------------------------------------------------------------
December 31, 2011 134 661 231 46 1,298
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROVED + PROBABLE
December 31, 2010 89 - 1,196 370 2,134
Discoveries 36 49 - - 152
Extensions & Improved Recovery 99 - 94 16 218
Acquisitions - - - - -
Revisions 3 - (124) - (87)
Divestments - - - - -
---------------------------------------------
Net Additions 138 49 (30) 16 283
Conversions (3) - - (94) (8) (130)
Reclassification to Bitumen (4) - 612 (517) - 95
Production (7) - (5) (8) (76)
----------------------------------------------------------------------------
December 31, 2011 220 661 550 370 2,306
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1. Other International includes Yemen, Nigeria and Colombia.
2. Includes reserves for which there are no definitive plans for upgrading
at this time.
3. Represents probable reserves converted to proved.
4. Reserves reclassified to bitumen as we no longer have sufficient
certainty as to when we will build additional upgrading facilities at
Kinosis.
Nexen Inc.
Financial Highlights
Three Months Ended Twelve Months Ended
Dec 31 Dec 31 Dec 31 Dec 31
(Cdn$ millions, except per-share
amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
Net Sales (1) 1,665 1,643 6,211 6,090
Cash Flow from Operations (1) 585 556 2,368 2,150
Per Common Share ($/share) 1.11 1.06 4.49 4.10
Net Income (1) 43 160 697 1,127
Per Common Share ($/share) 0.08 0.30 1.32 2.15
Capital Investment (2) 817 685 2,575 2,724
Net Debt (3) 3,538 4,085 3,538 4,085
Common Shares Outstanding (millions
of shares) 527.9 525.7 527.9 525.7
----------------------------------------
1. Includes discontinued operations as discussed in Note 14 to our
Unaudited Condensed Consolidated Financial Statements.
2. Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
3. Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
Cash Flow from Operations (1)
Three Months
Ended Twelve Months Ended
Dec 31 Dec 31 Dec 31 Dec 31
(Cdn$ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Conventional Oil & Gas
United Kingdom 854 780 3,085 2,775
North America (2) 46 67 252 359
Other Countries (3) 93 79 390 371
Oil Sands
In Situ 22 (8) 5 (127)
Syncrude 89 95 405 298
----------------------------------------
1,104 1,013 4,137 3,676
Interest, Marketing and Other
Corporate Items (2) (130) (166) (367) (567)
Income Taxes (4) (389) (291) (1,402) (959)
----------------------------------------
Cash Flow from Operations (1) 585 556 2,368 2,150
----------------------------------------
----------------------------------------
1. Defined as cash flow from operating activities before changes in non-
cash working capital and other. We evaluate our performance and that of
our business segments based on earnings and cash flow from operations.
Cash flow from operations is a non-GAAP term that represents cash
generated from operating activities before changes in non-cash working
capital and other. We consider it a key measure as it demonstrates our
ability to generate the cash flow necessary to fund future growth
through capital investment. Cash flow from operations may not be
comparable with the calculation of similar measures for other companies.
Three Months Ended Twelve Months Ended
Dec 31 Dec 31 Dec 31 Dec 31
(Cdn$ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash Flow from Operating Activities 459 342 2,497 2,392
Changes in Non-Cash Working Capital 32 72 (255) (338)
Other 102 141 158 128
Impact of Annual Crude Oil Put
Options (8) 1 (32) (32)
----------------------------------------
Cash Flow from Operations 585 556 2,368 2,150
----------------------------------------
----------------------------------------
Weighted-average Number of Common
Shares Outstanding (millions of
shares) 527.9 525.6 527.2 524.7
----------------------------------------
Cash Flow from Operations Per Common
Share ($/share) 1.11 1.06 4.49 4.10
----------------------------------------
----------------------------------------
2. Includes discontinued operations as discussed in Note 14 to our
Unaudited Condensed Consolidated Financial Statements.
3. After in-country cash taxes in Yemen of $36 million for the three months
ended December 31, 2011 (December 31, 2010 - $41 million) and $182
million for the twelve months ended December 31, 2011 (December 31, 2010
- $166 million).
4. Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months Twelve Months
Ended Dec 31 Ended Dec 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.8 109.4 85.0 104.9
Yemen 26.5 40.1 32.9 41.3
Oil Sands - Syncrude 18.2 22.8 20.9 21.2
Oil Sands - Long Lake Bitumen 20.5 18.3 18.6 15.9
United States 7.2 10.1 8.2 9.9
Canada (2) - - - 7.5
Other Countries 1.6 1.9 1.7 2.1
--------------------------------------
172.8 202.6 167.3 202.8
--------------------------------------
Natural Gas (mmcf/d)
United Kingdom 22 33 30 35
United States 66 99 86 99
Canada (2) 124 129 123 126
--------------------------------------
212 261 239 260
--------------------------------------
Total Production (mboe/d) 208 246 207 246
--------------------------------------
--------------------------------------
Production Volumes (after royalties)
Three Months Twelve Months
Ended Dec 31 Ended Dec 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.3 109.4 84.7 104.8
Yemen 15.5 23.6 18.1 23.1
Oil Sands - Syncrude 16.4 21.0 19.2 19.6
Oil Sands - Long Lake Bitumen 19.4 17.5 17.3 15.1
United States 6.3 9.3 7.4 9.0
Canada (2) - - - 5.8
Other Countries 1.5 1.8 1.6 1.9
--------------------------------------
157.4 182.6 148.3 179.3
--------------------------------------
Natural Gas (mmcf/d)
United Kingdom 22 33 30 35
United States 72 115 78 94
Canada (2) 118 121 117 116
--------------------------------------
212 269 225 245
--------------------------------------
Total Production (mboe/d) 193 227 186 220
--------------------------------------
--------------------------------------
1. We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
2. Includes the following production from discontinued operations. (See
Note 14 to our Unaudited Condensed Consolidated Financial Statements).
Three Months Twelve Months
Ended Dec 31 Ended Dec 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Before Royalties
Crude Oil and NGLs (mbbls/d) - - - 7.5
Natural Gas (mmcf/d) - - - 6
After Royalties
Crude Oil and NGLs (mbbls/d) - - - 5.8
Natural Gas (mmcf/d) - - - 5
----------------------------------------
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Total
Quarters - 2011 Year
----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2011
----------------------------------------------------------------------------
PRICES:
Brent Crude Oil (US$/bbl) 104.97 117.36 113.47 109.31 111.28
WTI Crude Oil (US$/bbl) 94.10 102.56 89.76 94.06 95.12
Nexen Average - Oil (Cdn$/bbl) 98.37 110.28 103.98 108.44 105.21
NYMEX Natural Gas (US$/mmbtu) 4.20 4.37 4.06 3.48 4.03
AECO Natural Gas (Cdn$/mcf) 3.58 3.54 3.53 3.29 3.48
Nexen Average - Gas (Cdn$/mcf) 4.51 4.75 4.36 3.63 4.31
----------------------------------------------------------------------------
NETBACKS (1):
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 104.2 73.3 75.2 92.7 86.3
Price Received ($/bbl) 99.97 110.67 107.58 110.46 106.76
Natural Gas:
Sales (mmcf/d) 36 37 26 22 30
Price Received ($/mcf) 7.29 8.20 7.28 6.52 7.42
Total Sales Volume (mboe/d) 110.2 79.5 79.5 96.4 91.3
Price Received ($/boe) 96.91 105.87 104.13 107.70 103.32
Royalties & Other - 0.11 0.82 0.54 0.36
Operating Costs 9.85 8.48 14.46 9.99 10.60
In-country Taxes 42.46 42.76 41.00 43.24 42.41
----------------------------------------------------------------------------
Netback 44.60 54.52 47.85 53.93 49.95
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 9.2 8.9 7.7 7.2 8.2
Price Received ($/bbl) 91.39 101.89 96.00 110.89 99.65
Natural Gas:
Sales (mmcf/d) 103 96 81 66 86
Price Received ($/mcf) 4.36 4.42 4.27 3.59 4.21
Total Sales Volume (mboe/d) 26.3 24.9 21.2 18.2 22.6
Price Received ($/boe) 48.91 53.56 50.72 57.27 52.31
Royalties & Other 5.65 6.11 5.63 3.31 5.30
Operating Costs 10.43 10.72 11.18 16.73 11.96
----------------------------------------------------------------------------
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