Nexen Announces Third Quarter 2012 Results & Progress on Strategic Priorities
CALGARY, Canada, October 25, 2012 /PRNewswire/ --
Met Third Quarter Production Guidance and On-Track to Meet Annual Production Guidance
Nexen Inc. (TSX, NYSE: NXY) today reported third quarter operating and financial results and provided an update on strategic priorities.
Production volumes averaged 181,000 barrels of oil equivalent per day (boe/d), a decrease from second quarter production of 213,000 boe/d. This reflects the scheduled downtime associated with the turnarounds at Buzzard, Long Lake and Scott.
Cash flow from operations decreased to $560 million ($1.06/share) from $707 million ($1.34/share) in the second quarter, primarily due to the lower production and higher operating costs associated with the planned turnarounds. Net income decreased to $59 million ($0.11/share) from $109 million ($0.20/share) in the second quarter. This reflects lower cash flow associated with the scheduled turnarounds and the impact of several non-recurring items.
We continue to make good progress on our strategic priorities:
- Buzzard operations were strong prior to the turnaround with a production efficiency of 88% versus our plan of 85%.
- Offshore West Africa, we brought on two additional wells at Usan and increased current production to approximately 120,000 barrels per day (bbls/d) (24,000 bbls/d net to Nexen).
- The planned major turnaround at Long Lake was completed without any significant issues. Bitumen production is back to approximately 34,000 bbls/d and the upgrader is producing PSC[TM]. Pad 12 continues to ramp-up and steaming continues at pad 13. First production is expected from pad 13 over the next several weeks.
- In the Gulf of Mexico, we completed a successful appraisal of the south fault block at Appomattox. We are currently drilling a sidetrack to test additional resource potential in the northwest fault block.
- Our previously announced shale gas joint venture with INPEX Gas British Columbia Ltd. (IGBC) closed in August and we received $821 million of cash upon closing. As well, our 18-well pad in the Horn River achieved start up in late September ahead of schedule.
- A number of exploration wells are in progress including North Uist and Bardolph in the UK North Sea. The Owowo West prospect, offshore West Africa is currently being evaluated.
"In the third quarter, we announced a plan to accelerate shareholder value while remaining focused on executing our plan and advancing strategic priorities across our operations," said Kevin Reinhart, Nexen's interim President & CEO. "We completed major turnarounds at Buzzard and Long Lake, met production guidance for the fourth consecutive quarter, and remained on-track to meet our production guidance for the year. Our ability to maintain focus and make continued strong progress in key areas of our operations is a testament to the talent and exceptional dedication of Nexen employees."
CNOOC Limited Offer for Nexen
On July 23, 2012, Nexen entered into an Arrangement Agreement under which CNOOC Limited proposes to acquire all of the outstanding common and preferred shares of Nexen for approximately US$15 billion in cash. On September 20, 2012, holders of Nexen's common and preferred shares approved the Plan of Arrangement, pursuant to the Arrangement Agreement. The closing of the arrangement remains subject to the receipt of required regulatory approvals and the satisfaction or waiver of the other customary closing conditions. We continue to expect the arrangement to close in the fourth quarter of 2012.
Operational Update
Conventional
UKNorth Sea - Buzzard production efficiency was strong in the third quarter prior to the turnaround, averaging 88% (86% year-to-date). This exceeds our target of 85% efficiency, excluding planned downtime.
The scheduled major turnaround at Buzzard that began in early September was completed with no significant issues discovered, although it did take longer than expected. We are in the process of restarting the platform, and expect production to ramp-up in the next week to 10 days.
The scheduled turnaround at Scott began in late July and was completed by the end of August.
The Golden Eagle development continues to progress towards first oil in late 2014. The fabrication of the platform facilities is well underway and construction is on-time and on-budget.
Drilling continues on our North Uist exploration prospect, which is located west of the Shetland Islands. The well has experienced delays due to mechanical issues, and results from the BP-operated well are now expected around the end of 2012.
Drilling is underway on our Bardolph exploration prospect in the North Sea. We have a 51% working interest in Bardolph. Results from this well are expected in the fourth quarter. Drilling is also underway at East Rochelle. Once drilling is completed, East Rochelle will be tied-back to our Scott platform.
Offshore West Africa - In July, we spudded an exploration well at Owowo West on block OPL-223. Drilling is now complete and we are evaluating the results. This well is in close proximity to our oil discovery at Owowo South B.
Oil production from Usan started in late February on block OML-138, offshore Nigeria. Nine wells are now on-stream, and during the quarter, daily production rates ranged from 90,000 - 122,000 bbls/d (18,000 - 24,000 bbls/d net to Nexen). We expect to bring on two additional wells over the next three months.
Gulf of Mexico - Our top priority in the Gulf of Mexico is continuing our exploration and appraisal program in the Norphlet play, including the Appomattox structure, along with the operator, Shell Gulf of Mexico Inc.
At Appomattox, we have booked 65 million barrels of probable reserves in the south fault block structure and added 50 million barrels of net contingent resource in the northeast fault block. A successful appraisal well in the south fault block of the structure confirmed reservoir quality at the upper end of our expectations. We are currently drilling a sidetrack from the appraisal well to test the incremental resource potential in the northwest fault block. Results are expected by the end of the year.
We have five more exploration and appraisal targets in the Norphlet play that we plan to test over the next twelve months. These wells will allow us to progress a development plan for Appomattox and continue to test the potential of the significant acreage position we have accumulated in the area.
We have a 20% interest in Appomattox, a 25% interest in Vicksburg and similar interests in numerous other blocks in the Norphlet play. The remaining interest is held by Shell.
During the third quarter we concluded negotiations around the Knotty Head-Pony field unitization. Nexen was the operator of the Knotty Head portion of the field and had a 25% working interest. Under the new equity agreement, Hess Corporation is the operator of the expanded Knotty Head-Pony project and all parties have a 20% working interest.
Oil Sands
LongLake - Production from Long Lake was 21,400 bbls/d of bitumen (gross), which was down from the second quarter due to the planned turnaround.
The scheduled turnaround began in mid-August and was completed by early October. During the turnaround, we carried out all required regulatory inspections, scheduled maintenance and preliminary preparation for future pads as planned without any significant issues.
With the turnaround complete, production is currently around 34,000 bbls/d. At pad 11, production continues to meet our expectations and recent weekly averages estimated at 6,000 bbls/d are consistent with production rates during the second quarter. At pad 12, we are currently producing from all nine wells. The nine well pairs on pad 13 are continuing to receive steam and first production is expected over the next several weeks.
The cash outflow during the quarter primarily reflects the impact of the turnarounds, including the expensed portion of the related costs and reduced production. Per-barrel operating costs were higher than normal due to the lower volumes.
Long Lake Quarterly Operating Metrics Bitumen Steam Unit Cash Realized Production (Gross) Injection (Gross) Operating Cost[1] Flow Price (bbls/d) (bbls/d) ($/bbl) ($ millions) ($/bbl) 2012 Q3 21,400 112,400 77[2] (64) 80 Q2 33,700 170,000 70 4 87 Q1 34,500 163,000 69 18 94 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
- Unit operating costs and realized prices are before royalties and based on PSC™ and bitumen volumes sold and exclude activities related to third-party bitumen purchased, processed and sold. Unit operating cost includes energy costs.
- Excludes costs related to the scheduled turnaround.
We continue to make good progress towards filling the upgrader over the next few years with additional wells in good-quality resource:
Number Expected Peak of Well Pairs Rates bbls/d Status Pad 12 is producing and pad 13 is being converted to production. Pads 12 & 13 18 11,000 - 17,000 Ramp-up over 12 - 24 month period. Pads 14 & 15 11 4,000 - 7,000 Drilling underway. Steam in second half of 2013. Kinosis 1A 29 15,000 - 25,000 Drilling underway. Steam in 2014.
Nexen has a 65% working interest in both Long Lake and Kinosis and is the operator. CNOOC Canada Inc. holds a 35% working interest in both Long Lake and Kinosis.
Shale Gas
Northeast British Columbia - Our previously announced joint venture agreement with IGBC closed in August. We received $821 million of cash comprised of the cash consideration, reimbursement of IGBC's share of costs since July 1, 2011 (effective date) and IGBC's carry component of our costs since July 1, 2011. There continues to be approximately $60 million of carry remaining. Upon closing, we recognized an after-tax gain of $106 million. Nexen and IGBC plan to develop our shale gas resource as economic conditions permit. We have also agreed to jointly investigate the feasibility of LNG export opportunities.
We continued our execution excellence in the Horn River with the completion of our 18-well pad, setting an industry record of 6.3 fracs/day. Production testing of this pad started in late September, ahead of schedule.
Production Summary
Average Daily Quarterly Average Daily Quarterly Production before Royalties Production after Royalties Crude Oil, NGLs and Natural Gas (mboe/d) Q3 2012 Q2 2012 Q3 2011 Q3 2012 Q2 2012 Q3 2011 UK - Buzzard 60 84 49 60 84 49 UK - Other 26 30 22 26 30 22 Canada - Syncrude 23 17 22 22 17 21 West Africa 20 20 - 18 18 - Canada - Oil & Gas 18 20 19 17 20 17 United States 14 14 21 13 13 19 Canada - In Situ 14 22 19 13 20 17 Other Countries 6 6 34 3 5 19 Total 181 213 186 172 207 164
Production decreased 15% from the second quarter on a before-royalties basis and 17% on an after-royalties basis. The decrease primarily reflects the impact of scheduled turnarounds at Long Lake, Buzzard and Scott.
Guidance Update
Average Daily Production before Royalties Q4 2012 Q4 2012 Crude Oil, NGLs and Q1 2012 Q2 2012 Q3 2012 Q3 2012 Original Adjusted 2012 Annual Natural Gas (mboe/d) Actual Actual Estimate Actual Estimate Estimate Estimate UK - Buzzard 82 84 50 - 60 60 75 - 95 50 - 60 70 - 85 UK - Other 29 30 20 - 26 26 25 - 32 25 - 32 24 - 32 Canada - Syncrude 21 17 22 - 24 23 22 - 24 22 - 24 21 - 23 West Africa 3 20 20 - 35 20 22 - 35 22 - 30 14 - 28 Canada - Oil & Gas 22 20 15 - 17 18 15 - 20 15 - 20 15 - 19 United States 16 14 13 - 17 14 15 - 17 15 - 17 15 - 19 Canada - In Situ 22 22 14 - 18 14 22 - 28 22 - 28 19 - 25 Other Countries 7 6 2 6 2 2 2 202 213 ~160 - 190 181 ~205 - 240 ~180 - 200 ~185 - 220
In the third quarter, production of 181,000 boe/d was at the upper end of our production guidance primarily due to the timing of the Buzzard turnaround.
We are adjusting our fourth quarter guidance to 180,000 - 200,000 boe/d to reflect the timing and the length of the turnaround at Buzzard, as well as our updated expectations of production at Usan. Our expectations for our annual production guidance at Buzzard and Usan remain unchanged. We are also on-track to meet our annual production guidance of 185,000 - 220,000 boe/d. Buzzard, Usan and Long Lake continue to be the critical drivers of our guidance range.
Financial Results
Three Months Ended Nine Months Ended Sept. 30 June 30 Sept. 30 Sept. 30 Sept. 30 (Cdn$ millions unless noted) 2012 2012 2011 2012 2011 Brent ($US/bbl) 110.13 108.66 113.47 112.64 111.94 WTI ($US/bbl) 92.22 93.49 89.76 96.21 95.48 NYMEX natural gas ($US/mmbtu) 2.90 2.35 4.06 2.58 4.21 Nexen Average Realized Oil & Gas Price ($/boe) 89.52 88.65 91.06 90.94 90.58 Cash netback ($/boe)[1] 48.90 44.51 38.67 46.32 39.43 Average Daily Production (mboe/d) Before Royalties 181 213 186 199 207 After Royalties 172 207 164 190 184 Cash flow from operations[2 ] 560 707 516 1,937 1,783 Per common share ($/share) 1.06 1.34 0.98 3.66 3.38 Net income 59 109 200 339 654 Per common share ($/share) 0.11 0.20 0.38 0.63 1.24 Capital investment[3] 831 743 729 2,331 1,758 Net debt[4] 2,367 3,136 3,454 2,367 3,454
- Cash netback is defined as our corporate average cash netback from oil and gas operations, after-tax. Excludes costs related to the scheduled turnaround at Long Lake.
- For reconciliation of this non-GAAP measure, see Cash Flow from Operations on pg. 8.
- Includes geological and geophysical expenditures.
- Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents.
The third quarter financial results were impacted by decreased production volumes and higher operating costs resulting from the planned turnarounds at Long Lake, Buzzard and Scott. Cash netbacks increased more than benchmark prices due to narrowing of Canadian differentials and increased contribution from our high-netback Usan production.
Net income decreased 46% from the prior quarter to $59 million ($0.11/share) due to lower cash flow associated with the planned turnarounds and the impact of several non-recurring items. These include an after-tax stock-based compensation charge of $99 million as a result of our share price appreciation following the CNOOC announcement and a deferred income tax charge of $63 million for changes to UK tax legislation. These charges were partially offset by the after-tax gain of $106 million on the shale gas joint venture.
Net debt decreased compared to the second quarter primarily due to the proceeds on closing of our shale gas joint venture.
Quarterly Dividends
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable January 1, 2013 to shareholders of record on December 10, 2012.
Due to the previously announced transaction with CNOOC Limited, the Board of Directors has determined not to declare the regular dividend on our Series 2 Preferred Shares at this time. This decision will have no effect on the amount to which holders of the Preferred Shares are entitled. If the transaction closes prior to December 31, 2012, holders of the Preferred Shares will receive consideration equal to $26 plus an amount equal to all accrued and unpaid dividends for each share held, up to but not including the date of closing. If the transaction does not close prior to December 31, 2012, the Board expects to declare a regular quarterly dividend to the shareholders of record, on a record date to be subsequently determined.
About Nexen
Nexen Inc. is a 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 29, 2011. For more information on our estimates of reserves, please refer to our 2011 Annual Information Form. For more information on our estimates of resource, please refer to our press releases dated November 15, 2010 and April 2, 2012.
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 or natural gas 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 facilities; the expected timing and associated production impact of facility 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 with them; dates by which certain areas will be developed, come on stream or reach expected operating capacity; the timing and anticipated receipt of required regulatory and court approvals for the arrangement with CNOOC Limited; the ability of the parties to satisfy the other conditions to, and to complete, the arrangement transaction; the anticipated timing of the closing of the arrangement transaction; 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 based on the information available to us on the date such assumptions were made, 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; the ability of the parties to the July 23 2012 Arrangement Agreement to receive, in a timely manner and on satisfactory terms, the necessary regulatory, court, stock exchange and other third party approvals, including but not limited to the receipt of applicable foreign investment approval required in Canada, the United States and elsewhere and the required approvals from the Government of the People's Republic of China and in other foreign jurisdictions; the ability of the parties to the Arrangement Agreement to satisfy, in a timely manner, the other conditions to the closing of the transaction; other expectations and assumptions concerning the arrangement transaction and the operations and capital expenditure plans of Nexen following completion of the transaction; 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.
Forward-looking statements are subject to known and unknown risks and uncertainties and other factors, many of which are beyond our control and each of which contributes to the possibility that our forward-looking statements will not occur or that actual results, levels of activity and achievements may 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 deep-water activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deep-water activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deep-water activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents and contractors, counterparties and joint venture partners; 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; the possible failure of Nexen and CNOOC Limited to obtain necessary regulatory, court and other third party approvals, including those noted above, or to otherwise satisfy the conditions to the completion of the transaction, in a timely manner or at all; if the arrangement transaction is not completed and Nexen continues as an independent entity, there are risks that the announcement of the transaction and the dedication of substantial resources of Nexen to the completion of the transaction could have an impact on Nexen's current business relationships (including with future and prospective employees, customers, distributors, suppliers and partners) and could have a material adverse effect on the current and further operations, financial condition and prospects of Nexen; the possible failure of Nexen to comply with the terms of the Arrangement Agreement may result in Nexen being required to pay a fee to CNOOC Limited, the result of which could have a material and adverse effect on Nexen's financial position and results of operations and its ability to fund growth prospects and current operations; and other factors, many of which are beyond our control.
These risks, uncertainties and other factors and their possible impact are discussed more fully in the sections titled "Risk Factors" in our 2011 Annual Information Form and "Quantitative and Qualitative Disclosures About Market Risk" in our 2011 annual MD&A. 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 as the plans, intentions, assumptions or expectations upon which they are based might not occur or come to fruition. Except as required by applicable securities laws, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Included herein is information that may be considered financial outlook and/or future-oriented financial information (FOFI). Its purpose is to indicate the potential results of our intentions and may not be appropriate for other purposes. The forward-looking statements contained herein are expressly qualified by this cautionary statement.
Note to Investors on Reserves and Resources
The reserves estimates in this disclosure were prepared with an effective date of December 31, 2011. The resource estimates were prepared on March 31, 2012. These estimates 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"). For more information on this reserves estimate and Nexen's reserves estimation process please refer to our 2011 Annual Information Form. For more information on our Appomattox resource estimate please refer to our press release dated April 2, 2012. Both our Annual Information Form and news releases are available athttp://www.nexeninc.comandhttp://www.sedar.com.
Conversions of gas volumes to boe in these estimates were made on the basis of 1 boe to 6 mcf of natural gas. A boe conversion ratio of 6 mcf:1 bbl 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. Disclosure provided herein in respect of boes may be misleading, particularly if used in isolation.
Nexen Inc.
Financial Highlights
Nine Months Three Months Ended Ended Sept. June Sept. Sept. Sept. 30 30 30 30 30 (Cdn$ millions, except per-share amounts) 2012 2012 2011 2012 2011 Net Sales [1] 1,495 1,659 1,399 4,850 4,546 Cash Flow from Operations [1] 560 707 516 1,937 1,783 Per Common Share, Basic ($/share) 1.06 1.34 0.98 3.66 3.38 Per Common Share, Diluted ($/share) 1.03 1.28 0.95 3.55 3.29 Net Income [1] 59 109 200 339 654 Per Common Share, Basic ($/share) 0.11 0.20 0.38 0.63 1.24 Capital Investment [2] 831 743 729 2,331 1,758 Net Debt [3] 2,367 3,136 3,454 2,367 3,454 Common Shares Outstanding (millions of shares) 530.0 529.3 527.4 530.0 527.4
[1] Includes results of discontinued operations. See Note 23 of our 2011 Annual Consolidated Financial Statements.
[2] Includes oil and gas development, exploration, and expenditures for other property, plant and equipment.
[3] Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents.
Cash Flow from Operations [1]
Three Months Ended Nine Months Ended Sept. 30 June 30 Sept. 30 Sept. 30 Sept. 30 (Cdn$ millions) 2012 2012 2011 2012 2011 Conventional Oil & Gas United Kingdom 737 919 645 2,721 2,231 North America 13 15 50 66 206 Other Countries [2] 182 165 132 366 443 Oil Sands In Situ (64) 4 (4) (42) (17) Syncrude 106 70 106 267 316 974 1,173 929 3,378 3,179 Interest, Marketing and Other Corporate Items (129) (70) (62) (280) (237)[3] Current Income Taxes (285) (396) (351) (1,161) (1,159) Cash Flow from Operations 560 707 516 1,937 1,783
[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 Nine Months Ended Sept. 30 June 30 Sept. 30 Sept. 30 Sept. 30 (Cdn$ millions) 2012 2012 2011 2012 2011 Cash Flow from Operating Activities 515 1,159 288 2,182 2,038 Changes in Non-Cash Working Capital 4 (446) 198 (296) (287) Other 53 6 38 87 56 Impact of Annual Crude Oil Put Options (12) (12) (8) (36) (24) Cash Flow from Operations 560 707 516 1,937 1,783 Weighted Average Number of Common Shares Outstanding, Basic (millions of shares) 530 529 527 529 527 Cash Flow from Operations Per Common Share, Basic ($/share) 1.06 1.34 0.98 3.66 3.38 Cash Flow from Operations, Diluted 566 713 522 1,956 1,802 Weighted Average Number of Common Shares Outstanding, Diluted (millions of shares) 550 556 550 551 547 Cash Flow from Operations Per Common Share, Diluted ($/share) 1.03 1.28 0.95 3.55 3.29
[2] Includes Nigeria, Yemen and Colombia.
[3] Includes results of discontinued operations. See Note 23 of our 2011 Annual Consolidated Financial Statements.
Nexen Inc.
Production Volumes (before royalties)[1]
Three Months Ended Nine Months Ended Sept. 30 June 30 Sept. 30 Sept. 30 Sept. 30 (mboe/d) 2012 2012 2011 2012 2011 Conventional Oil and Gas United Kingdom 85.8 114.2 71.1 103.6 85.7 North America [2] 32.3 34.4 39.7 34.9 44.8 Other Countries [3] 25.8 25.5 33.9 20.3 36.8 143.9 174.1 144.7 158.8 167.3 Oil Sands Long Lake Bitumen [4] 13.9 21.9 19.2 19.4 18.0 Syncrude 22.7 17.2 21.6 20.4 21.7 36.6 39.1 40.8 39.8 39.7 Total Production 180.5 213.2 185.5 198.6 207.0 Total Crude Oil and Liquids (mbbls/d) 150.6 178.7 149.2 165.6 165.5 Total Natural Gas (mmcf/d) 180[5] 207 218 198[6] 249
Production Volumes (after royalties)
Three Months Ended Nine Months Ended Sept. 30 June 30 Sept. 30 Sept. 30 Sept. 30 (mboe/d) 2012 2012 2011 2012 2011 Conventional Oil and Gas United Kingdom 85.2 113.7 70.7 103.1 85.5 North America [2] 30.0 33.1 36.0 32.8 40.7 Other Countries [3] 21.3 22.9 18.9 16.9 20.5 136.5 169.7 125.6 152.8 146.7 Oil Sands Long Lake Bitumen [4] 13.2 20.4 17.3 18.2 16.6 Syncrude 22.0 16.9 20.6 19.2 20.2 35.2 37.3 37.9 37.4 36.8 Total Production 171.7 207.0 163.5 190.2 183.5 Total Crude Oil and Liquids (mbbls/d) 143.4 173.2 130.0 158.5 145.2 Total Natural Gas (mmcf/d) 170 203 201 190 230
[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 shale gas production in Canada.
[3] Includes Nigeria, Yemen and Colombia.
[4] We report Long Lake bitumen as production.
[5] Includes 107 mmcf/d of natural gas production in Canada, 43 in the US and 30 in the UK (2011-111, 81 and 26, respectively).
[6] Includes 120 mmcf/d of natural gas production in Canada, 44 in the US and 34 in the UK (2011-123, 94 and 32, respectively).
Nexen Inc.
Oil and Gas Prices and Cash Netbacks [1]
Total Quarters - 2012 Quarters - 2011 Year (all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2011 PRICES: Brent Crude Oil (US$/bbl) 119.13 108.66 110.13 104.97 117.36 113.47 109.31 111.28 WTI Crude Oil (US$/bbl) 102.93 93.49 92.22 94.10 102.56 89.76 94.06 95.12 Nexen Average - Oil (Cdn$/bbl) 111.62 102.21 103.43 98.37 110.28 103.98 108.44 105.21 NYMEX Natural Gas (US$/mmbtu) 2.51 2.35 2.90 4.20 4.37 4.06 3.48 4.03 AECO Natural Gas (Cdn$/mcf) 2.39 1.74 2.08 3.58 3.54 3.53 3.29 3.48 Nexen Average - Gas (Cdn$/mcf) 3.13 2.58 3.19 4.51 4.75 4.36 3.63 4.31 NETBACKS [1]: United Kingdom Crude Oil: Sales (mbbls/d) 106.9 105.3 82.1 104.2 73.3 75.2 92.7 86.3 Price Received ($/bbl) 118.12 105.82 108.39 99.97 110.67 107.58 110.46 106.76 Natural Gas: Sales (mmcf/d) 33 31 31 36 37 26 22 30 Price Received ($/mcf) 7.83 6.64 7.43 7.29 8.20 7.28 6.52 7.42 Total Sales Volume (mboe/d) 112.3 110.4 87.3 110.2 79.5 79.5 96.4 91.3 Price Received ($/boe) 114.65 102.74 104.57 96.91 105.87 104.13 107.70 103.32 Royalties & Other 0.51 0.55 0.71 - 0.11 0.82 0.54 0.36 Operating Costs 10.14 10.90 13.78 9.85 8.48 14.46 9.99 10.60 In-country Taxes 45.41 38.84 32.04 42.46 42.76 41.00 43.24 42.41 Netback 58.59 52.45 58.04 44.60 54.52 47.85 53.93 49.95 Oil Sands - In Situ [2] Sales (mbbls/d) 17.8 16.5 11.2 12.9 14.3 11.8 16.7 13.9 Price Received ($/bbl) 94.45 86.58 80.13 89.82 108.78 94.15 97.28 98.33 Royalties & Other 4.79 6.10 3.22 3.58 6.05 5.07 5.29 5.05 Operating Costs 68.89 69.95 77.36[3] 89.43 95.34 85.42 67.41 83.44 Netback [2] 20.77 10.53 (0.45) (3.19) 7.39 3.66 24.58 9.84 Oil Sands - Syncrude Sales (mbbls/d) 21.3 17.2 22.7 23.2 20.4 21.6 18.2 20.8 Price Received ($/bbl) 92.54 89.85 91.48 94.60 111.79 97.65 104.32 101.73 Royalties & Other 11.25 (3.03) 1.84 4.30 13.82 4.65 10.59 8.10 Operating Costs 31.36 44.96 35.93 36.11 39.98 37.10 38.24 37.78 Netback 49.93 47.92 53.71 54.19 57.99 55.90 55.49 55.85 United States Crude Oil: Sales (mbbls/d) 8.0 7.3 7.4 9.2 8.9 7.7 7.2 8.2 Price Received ($/bbl) 108.40 102.19 99.04 91.39 101.89 96.00 110.89 99.65 Natural Gas: Sales (mmcf/d) 50 41 43 103 96 81 66 86 Price Received ($/mcf) 2.67 2.19 2.89 4.36 4.42 4.27 3.59 4.21 Total Sales Volume (mboe/d) 16.3 14.1 14.5 26.3 24.9 21.2 18.2 22.6 Price Received ($/boe) 61.33 58.84 58.91 48.91 53.56 50.72 57.27 52.31 Royalties & Other 6.02 6.12 6.50 5.65 6.11 5.63 3.31 5.30 Operating Costs 17.29 17.87 19.37 10.43 10.72 11.18 16.73 11.96 Netback 38.02 34.85 33.04 32.83 36.73 33.91 37.23 35.05
[1] Netbacks are defined as average sales price less royalties, other operating costs and in-country taxes.
[2] Excludes activities related to third-party bitumen purchased, processed and sold.
[3] Excludes costs related to turnaround activities.
Nexen Inc.
Oil and Gas Cash Netback [1](continued)
Total Quarters - 2012 Quarters - 2011 Year (all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2011 Canada - Natural Gas [2] Sales (mmcf/d) 131 120 105 97 85 79 112 93 Price Received ($/mcf) 2.12 1.67 2.05 3.65 3.62 3.51 3.08 3.44 Royalties & Other 0.08 (0.05) 0.06 0.28 0.24 0.27 0.17 0.23 Operating Costs 1.58 1.62 1.72 1.70 1.54 1.65 1.70 1.65 Netback 0.46 0.10 0.27 1.67 1.84 1.59 1.21 1.56 Other Countries [3] Sales (mbbls/d) 5.4 27.0 27.4 36.7 41.0 33.5 29.4 35.1 Price Received ($/bbl) 119.61 105.59 109.24 101.17 111.56 107.64 111.10 107.85 Royalties & Other 48.76 17.27 18.44 44.95 50.38 47.54 43.83 46.92 Operating Costs 13.02 17.70 14.42 10.62 9.23 12.97 19.89 12.73 In-country Taxes 9.31 2.50 1.94 12.81 15.58 14.71 13.27 14.17 Netback 48.52 68.12 74.44 32.79 36.37 32.42 34.11 34.03 Company-Wide Oil and Gas Sales (mboe/d) 195.0 205.2 180.6 225.5 194.3 180.7 197.6 199.2 Price Received ($/boe) 94.67 88.65 89.52 85.98 95.31 91.06 94.11 91.46 Royalties & Other 3.87 3.19 4.12 8.74 13.47 10.83 8.62 10.34 Operating Costs 18.56 19.74 20.71[4] 17.32 18.68 20.80 19.56 19.00 In-country Taxes 26.43 21.21 15.79 22.84 20.78 20.76 23.08 21.92 Netback 45.81 44.51 48.90 37.08 42.38 38.67 42.85 40.20
[1] Netbacks are defined as average sales price less royalties and other, operating costs and in-country taxes.
[2] Includes Canadian conventional, CBM and shale gas activities. Shale gas was included beginning in the fourth quarter of 2011 when it became commercial.
[3] Includes Yemen, Colombia and West Africa.
[4] Excludes costs related to turnaround activities.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Income
For the Three and Nine Months Ended September 30
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions, except per-share amounts) 2012 2011 2012 2011 Revenues and Other Income Net Sales 1,495 1,399 4,850 4,504 Marketing and Other Income (Note 8) 14 125 165 254 1,509 1,524 5,015 4,758 Expenses Operating 401 356 1,116 1,060 Depreciation, Depletion, Amortization and Impairment 427 409 1,312 1,114 Transportation and Other 128 110 353 289 General and Administrative 223 23 464 204 Exploration 49 59 264 278 Finance (Note 5) 80 59 225 193 Loss on Debt Redemption and Repurchase - - - 91 Gain from Dispositions (Note 10) (145) - (197) (12) 1,163 1,016 3,537 3,217 Income from Continuing Operations before Provision for Income Taxes 346 508 1,478 1,541 Provision for (Recovery of) Income Taxes Current 285 351 1,161 1,159 Deferred 2 (43) (22) 30 287 308 1,139 1,189 Net Income from Continuing Operations 59 200 339 352 Net Income from Discontinued Operations, Net of Tax - - - 302 Net Income Attributable to Nexen Inc. Shareholders 59 200 339 654 Earnings Per Common Share from Continuing Operations ($/share) (Note 6) Basic 0.11 0.38 0.63 0.67 Diluted 0.11 0.32 0.63 0.61 Earnings Per Common Share ($/share) (Note 6) Basic 0.11 0.38 0.63 1.24 Diluted 0.11 0.32 0.63 1.16
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Balance Sheet
September 30 December 31 (Cdn$ millions) 2012 2011 Assets Current Assets Cash and Cash Equivalents 1,870 845 Restricted Cash 18 45 Accounts Receivable 1,582 2,247 Derivative Contracts 62 119 Inventories and Supplies 351 320 Other 140 115 Total Current Assets 4,023 3,691 Non-Current Assets Property, Plant and Equipment (Note 3) 15,462 15,571 Goodwill 282 291 Deferred Income Tax Assets 482 338 Derivative Contracts 4 25 Other Long-Term Assets 98 152 Total Assets 20,351 20,068 Liabilities Current Liabilities Accounts Payable and Accrued Liabilities 2,591 2,867 Income Taxes Payable 609 458 Derivative Contracts 63 103 Total Current Liabilities 3,263 3,428 Non-Current Liabilities Long-Term Debt 4,237 4,383 Deferred Income Tax Liabilities 1,574 1,488 Asset Retirement Obligations 1,973 2,010 Derivative Contracts 4 24 Other Long-Term Liabilities 452 362 Equity (Note 6) Share Capital Common Shares 1,194 1,157 Preferred Shares 195 - Retained Earnings 7,465 7,211 Cumulative Translation Adjustment (6) 5 Total Equity 8,848 8,373 Total Liabilities and Equity 20,351 20,068
See accompanying notes to Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Cash Flows
For the Three and Nine Months Ended September 30
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions) 2012 2011 2012 2011 Operating Activities Net Income from Continuing Operations 59 200 339 352 Net Income from Discontinued Operations - - - 302 Charges and Credits to Income not Involving Cash (Note 9) 464 265 1,370 875 Exploration Expense 49 59 264 278 Changes in Non-Cash Working Capital (Note 9) (4) (198) 296 287 Other (53) (38) (87) (56) 515 288 2,182 2,038 Financing Activities Repayment of Long-Term Debt - - - (871) Issue of Common Shares 11 8 37 39 Issue of Preferred Shares - - 195 - Dividends Paid on Common and Preferred Shares (29) (26) (82) (78) Other - 1 (6) 2 (18) (17) 144 (908) Investing Activities Capital Expenditures Exploration, Evaluation and Development (807) (716) (2,261) (1,708) Corporate and Other (24) (13) (70) (50) Proceeds from Dispositions (Note 10) 828 1 881 475 Changes in Restricted Cash 83 1 27 (10) Changes in Non-Cash Working Capital (Note 9) 75 69 140 184 Other (2) - 3 (75) 153 (658) (1,280) (1,184) Effect of Exchange Rate Changes on Cash and Cash Equivalents (35) 100 (21) 74 Increase (Decrease) in Cash and Cash Equivalents 615 (287) 1,025 20 Cash and Cash Equivalents - Beginning of Period 1,255 1,312 845 1,005 Cash and Cash Equivalents - End of Period [1] 1,870 1,025 1,870 1,025
[1 ]Cash and cash equivalents at September 30, 2012 consists of cash of $620 million and short-term investments of $1,250 million (September 30, 2011 cash of $277 million and short-term investments of $748 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Changes in Equity
For the Three and Nine Months Ended September 30
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions) 2012 2011 2012 2011 Share Capital Common Shares, Beginning of Period 1,183 1,142 1,157 1,111 Issue of Common Shares 11 8 37 39 Common Shares, Balance at End of Period 1,194 1,150 1,194 1,150 Preferred Shares, Beginning of Period 195 - - - Issue of Preferred Shares - - 195 - Preferred Shares, Balance at End of Period 195 - 195 - Retained Earnings, Beginning of Period 7,435 7,094 7,211 6,692 Net Income Attributable to Nexen Inc. Shareholders 59 200 339 654 Dividends on Common and Preferred Shares (Note 6) (29) (26) (85) (78) Balance at End of Period 7,465 7,268 7,465 7,268 Cumulative Translation Adjustment, Beginning of Period 26 (55) 5 (37) Currency Translation Adjustment (35) 63 (30) 45 Realized Translation Adjustments [1] 3 - 19 - Balance at End of Period (6) 8 (6) 8
[1 ]Net of income tax recovery for the three months ended September 30, 2012 of $2 million (2011 - net of income tax expense of $4 million) and net of income tax recovery for the nine months ended September 30, 2012 of $9 million (2011 - net of income tax expense of $24 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Comprehensive Income
For the Three and Nine Months Ended September 30
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions) 2012 2011 2012 2011 Net Income Attributable to Nexen Inc. Shareholders 59 200 339 654 Other Comprehensive Income (Loss): Currency Translation Adjustment Net Translation Gains (Losses) of Foreign Operations (163) 339 (149) 200 Net Translation Gains (Losses) on US$-Denominated Debt Hedging of Foreign Operations [1] 128 (276) 119 (155) Total Currency Translation Adjustment (35) 63 (30) 45 Total Comprehensive Income 24 263 309 699
[1 ]Net of income tax expense for the three months ended September 30, 2012 of $18 million (2011 - net of income tax recovery of $39 million) and net of income tax expense for the nine months ended September 30, 2012 of $17 million (2011 - net of income tax recovery of $22 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cdn$ millions, except as noted
1. BASIS OF PRESENTATION
Nexen Inc. (Nexen, we or our) is an independent, global energy company with operations in the UK North Sea, US Gulf of Mexico, offshore Nigeria, Canada, Yemen, Colombia and Poland. Nexen is incorporated and domiciled in Canada and our head office is located at 801-7th Avenue SW, Calgary, Alberta, Canada. Nexen's shares are publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange.
These Unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2012 have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Specifically, they have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting. The Unaudited Condensed Consolidated Financial Statements do not include all of the information required for annual financial statements and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2011, which have been prepared in accordance with IFRS.
CNOOC Acquisition of Nexen
On July 23, 2012, Nexen and CNOOC Limited (CNOOC) entered into an Arrangement Agreement in which CNOOC proposed to acquire all of the outstanding shares of Nexen Inc. for US$27.50 per common share and Cdn$26.00 per preferred share. The transaction is proposed to be completed by way of a plan of arrangement (the "Arrangement") under the Canada Business Corporations Act. On September 20, 2012, Nexen's common and preferred shareholders approved the Arrangement, and the Court of Queen's Bench of Alberta granted a final order approving the Arrangement. The closing of the Arrangement remains subject to the receipt of required regulatory approvals and the satisfaction or waiver of the other customary closing conditions.
The Unaudited Condensed Consolidated Financial Statements were authorized for issue by Nexen's Board of Directors on October 24, 2012.
2. ACCOUNTING POLICIES
The accounting policies we follow are described in Note 2 of the Audited Consolidated Financial Statements for the year ended December 31, 2011. There have been no changes to our accounting policies since December 31, 2011.
3.PROPERTY, PLANT AND EQUIPMENT (PP&E)
(a) Carrying amount of PP&E
Exploration Assets Producing and Under Oil & Gas Corporate Evaluation Construction Properties and Other Total Cost As at December 31, 2011 2,206 2,347 19,832 837 25,222 Additions 546 581 1,134 70 2,331 Disposals/Derecognitions (187) - (925) (15) (1,127) Transfers [1] - (1,862) 1,862 - - Exploration Expense (264) - - - (264) Other (6) - 90 18 102 Effect of Changes in Exchange Rate (39) (32) (375) (7) (453) As at September 30, 2012 2,256 1,034 21,618 903 25,811 Accumulated Depreciation, Depletion & Amortization (DD&A) As at December 31, 2011 368 - 8,860 423 9,651 DD&A 44 - 1,203 65 1,312 Disposals/Derecognitions (16) - (307) (12) (335) Other - - (27) 17 (10) Effect of Changes in Exchange Rate (11) - (253) (5) (269) As at September 30, 2012 385 - 9,476 488 10,349 Net Book Value As at December 31, 2011 1,838 2,347 10,972 414 15,571 As at September 30, 2012 1,871 1,034 12,142 415 15,462
[1 ]Includes PP&E costs related to our Usan development, offshore Nigeria which came on-stream February 2012.
Exploration and evaluation assets mainly comprise of unproved properties and capitalized exploration drilling costs. Assets under construction at September 30, 2012 primarily include our developments in the UK North Sea.
(b) Impairment
DD&A expense for the third quarter of 2011 includes non-cash impairment charges of $141 million for our Canadian coalbed methane and conventional gas assets. Sustained lower natural gas prices in the quarter reduced our estimates of fair value and resulted in impairment of the properties' carrying value.
4.LONG-TERM DEBT
During the three and nine months ended September 30, 2012, we borrowed and repaid nil and $254 million on our term credit facilities, respectively. We recorded $146 million and $136 million, respectively, of unrealized foreign exchange gains on long-term debt in other comprehensive income.
We have undrawn, committed, unsecured term credit facilities of $3.7 billion, of which $700 million is available until 2014 and $3.0 billion is available until 2017. As at September 30, 2012, $232 million of our term credit facilities were utilized to support letters of credit (December 31, 2011-$367 million).
Nexen has undrawn, uncommitted, unsecured credit facilities of approximately $180 million. We utilized $5 million of these facilities to support outstanding letters of credit at September 30, 2012 (December 31, 2011-$17 million).
Nexen has undrawn, uncommitted, unsecured credit facilities of approximately $207 million exclusively to support letters of credit. We utilized $16 million of these facilities to support outstanding letters of credit at September 30, 2012 (December 31, 2011-$4 million).
5.FINANCE EXPENSE
Three Months Nine Months Ended September 30 Ended September 30 2012 2011 2012 2011 Interest on Long-Term Debt 75 73 223 231 Accretion Expense Related to Asset Retirement Obligations 13 12 39 35 Other Interest and Fees 6 7 18 17 Total 94 92 280 283 Less: Capitalized at 6.7% (2011 - 6.7%) (14) (33) (55) (90) Total 80 59 225 193
Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings.
6.EQUITY
(a) Common Shares
Authorized share capital consists of an unlimited number of common shares of no par value. At September 30, 2012, there were 530,005,285 common shares outstanding (December 31, 2011-527,892,635 common shares).
(b) Preferred Shares
Authorized share capital consists of an unlimited number of Class A preferred shares of no par value, issuable in series. At September 30, 2012, there were 8,000,000 Cumulative Redeemable Class A Rate Reset Preferred Shares, Series 2 outstanding (December 31, 2011-nil).
(c) Earnings Per Common Share (EPS)
We calculate basic EPS using net income attributable to Nexen Inc. common shareholders, adjusted for preferred share dividends and divided by the weighted-average number of common shares outstanding. We calculate diluted EPS in the same manner as basic, except we adjust basic earnings for the potential conversion of the subordinated debentures and potential exercise of outstanding tandem options for shares, if dilutive. We use the weighted-average number of diluted common shares outstanding in the denominator of our diluted EPS calculation.
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions) 2012 2011 2012 2011 Net Income Attributable to Nexen Inc. Common Shareholders 59 200 339 654 Preferred Share Dividends Payable (3) - (6) - Net Income Attributable to Nexen Inc. Common Shareholders, Basic 56 200 333 654 Potential Tandem Options Exercises - (29) - (39) Potential Conversion of Subordinated Debentures - 6 - 19 Net Income Attributable to Nexen Inc. Common Shareholders, Diluted 56 177 333 634 (millions of shares) Weighted Average Number of Common Shares Outstanding, Basic 530 527 529 527 Common Shares Issuable Pursuant to Tandem Options - 2 - 2 Common Shares Notionally Purchased from Proceeds of Tandem Options - (2) - (2) Common Shares Issuable Pursuant to Potential Conversion of Subordinated Debentures - 23 - 20 Weighted Average Number of Common Shares Outstanding, Diluted 530 550 529 547
In calculating the weighted-average number of diluted common shares outstanding and related earnings adjustments for the three and nine months ended September 30, 2012, we excluded 8,118,453 and 11,390,032 tandem options, respectively (2011-15,162,013 and 15,081,166, respectively) because their exercise price was greater than the average common share market price during those periods. During the three and nine months ended September 30, 2012, there were no dilutive instruments. During the three and nine months ended September 30, 2011, the potential conversion of tandem options and subordinated debentures were the only dilutive instruments.
(d) Dividends
We paid dividends of $0.05 and $0.15 per common share, for the three and nine months ended September 30, 2012 ($0.05 and $0.15 per common share for the respective periods ended September 30, 2011).
We paid dividends of $0.3928 per preferred share, for the three and nine months ended September 30, 2012 (nil paid per preferred share for the respective periods ended September 30, 2011).
Dividends paid to holders of common and preferred shares have been designated as "eligible dividends" for Canadian tax purposes.
On October 24, 2012, the Board of Directors declared a quarterly dividend of $0.05 per common share, payable January 1, 2013 to the shareholders of record on December 10, 2012.
(e) Stock-Based Compensation
Three Months Ended September 30, 2012 (thousands of shares) Options STARs RSUs PSUs Outstanding, Beginning of Period 14,966 13,584 3,793 599 Granted - - 23 - Exercised for Stock (107) - - - Exercised or Redeemed for Cash (510) (822) (1) - Cancelled (169) (252) (119) (14) Expired - (13) - - Outstanding, End of Period 14,180 12,497 3,696 585 Nine Months Ended September 30, 2012 (thousands of shares) Options STARs RSUs PSUs Outstanding, Beginning of Period 14,854 14,407 2,025 390 Granted 1,368 339 1,936 312 Exercised for Stock (107) - - - Exercised or Redeemed for Cash (552) (962) (4) - Cancelled (1,333) (1,173) (261) (117) Expired (50) (114) - - Outstanding, End of Period 14,180 12,497 3,696 585 Exercisable, End of Period 7,710 8,729
Options and STARs granted in the nine months ended September 30, 2012 have a weighted average exercise price of $19.26/unit. No options or STARs were granted during the three months ended September 30, 2012. We recognized compensation expense related to share-based payments in the amount of $116 and $140 million (2011-compensation recovery $65 and $62 million) for the three and nine months ended September 30, 2012, respectively.
7.COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 19 to the 2011 Audited Consolidated Financial Statements, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe that payments, if any, related to existing indemnities would not have a material adverse effect on our liquidity, financial condition or results of operations.
We assume various contractual obligations and commitments in the normal course of our operations. During the quarter, we entered into drilling rig commitments comprised of the following:
2012 2013 2014 2015 2016 Thereafter Drilling Rig Commitments 17 60 23 9 - -
The commitments above are in addition to those included in Note 19 to the 2011 Audited Consolidated Financial Statements and Note 7 to the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2012 and June 30, 2012.
8. MARKETING AND OTHER INCOME
Three Months Nine Months Ended September 30 Ended September 30 2012 2011 2012 2011 Marketing Revenue, Net 35 72 210 174 Interest Income 15 - 16 3 Foreign Exchange Gains (Losses) (55) 30 (59) 14 Change in Fair Value of Crude Oil Put Options (4) 13 (38) 6 Insurance Proceeds - - - 26 Other 23 10 36 31 Total 14 125 165 254
9. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Nine Months Ended September 30 Ended September 30 2012 2011 2012 2011 Depreciation, Depletion, Amortization and Impairment 427 409 1,312 1,114 Gain from Dispositions (145) - (197) (12) Change in Fair Value of Crude Oil Put Options 4 (13) 38 (6) Non-cash Stock-Based Compensation (Recovery) 108 (65) 132 (67) Foreign Exchange 51 (31) 59 (14) Provision for (Recovery of) Deferred Income Taxes 2 (43) (22) 30 Loss on Debt Redemption and Repurchase - - - 91 Non-Cash Items Included in Discontinued Operations - - - (290) Other 17 8 48 29 Total 464 265 1,370 875
(b) Changes in non-cash working capital
Three Months Nine Months Ended September 30 Ended September 30 2012 2011 2012 2011 Accounts Receivable 294 61 807 (73) Inventories and Supplies (105) (3) (65) 181 Other Current Assets (6) (4) (23) (13) Accounts Payable and Accrued Liabilities 143 114 (403) 283 Current Income Taxes Payable (255) (297) 120 93 Total 71 (129) 436 471 Relating to: Operating Activities (4) (198) 296 287 Investing Activities 75 69 140 184 Total 71 (129) 436 471
(c) Other cash flow information
Three Months Nine Months Ended September 30 Ended September 30 2012 2011 2012 2011 Interest Paid 89 88 237 218 Income Taxes Paid 527 646 1,024 1,106
10. DISPOSITIONS
Asset Dispositions
Canadian Shale Gas Joint Venture
During the quarter, we closed the sale of a 40% working interest in our northeast British Columbia shale gas operations to INPEX Gas British Columbia Ltd. (IGBC). Upon closing we received $821 million in cash, comprised of the initial cash payment, the carry associated with Nexen's capital and IGBC's share of costs since the July 1, 2011 effective date of the transaction. We recorded a pre-tax gain on sale of $142 million on closing.
11.OPERATING SEGMENTS AND RELATED INFORMATION
Nexen has the following operating segments:
Conventional Oil and Gas: We explore for, develop and produce crude oil and natural gas from conventional sources around the world. Our operations are focused in the UK North Sea, North America (Canada and US) and other countries (offshore Nigeria, Colombia, Yemen and Poland).
Oil Sands: We develop and produce synthetic crude oil from the Athabasca oil sands in northern Alberta. We produce bitumen using in situ and mining technologies and upgrade it into synthetic crude oil before ultimate sale. Our in situ activities are comprised of our operations at Long Lake and future development phases. Our mining activities are conducted through our 7.23% ownership of the Syncrude Joint Venture.
Shale Gas: We explore for and produce unconventional gas from shale formations in northeast British Columbia. Production and results of operations are included within Conventional Oil and Gas until they become significant.
Corporate and Other includes energy marketing and unallocated items. The results of Canexus have been presented as discontinued operations.
The accounting policies of our operating segments are the same as those described in Note 2 of our Audited Consolidated Financial Statements for the year ended December 31, 2011. Net income (loss) of our operating segments excludes interest income, interest expense, income tax expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.
Segmented net income for the three months ended September 30, 2012
Corporate Conventional Oil Sands and Total United North Other Kingdom America Countries In Situ Syncrude Other Net Sales 834 90 228 143 188 12 1,495 Marketing and Other Income 20 3 - - - (9) 14 854 93 228 143 188 3 1,509 Less: Expenses Operating 111 42 37 131[2] 75 5 401 Depreciation, Depletion and Amortization 157 65 133 40 17 15 427 Transportation and Other (1) 14 - 66 6 43 128 General and Administrative 17 46 26 21 1 112[3] 223 Exploration 11 28 9[4] 1 - - 49 Finance 6 3 - 1 2 68 80 Gain from Dispositions (2) (143) - - - - (145) Income (Loss) before Income Taxes 555 38 23 (117) 87 (240) 346 Less: Provision for Income Taxes 287[5] Net Income 59 Capital Expenditures 270 178 89[6] 217 67 10 831
[1]Includes results of operations in Nigeria, Yemen and Colombia.
[2]Includes Long Lake turnaround costs of $49 million.
[3]Includes non-cash stock-based compensation expense of $108 million.
[4] Includes exploration activities primarily in Colombia and Poland.
[5] Includes UK current tax expense of $278 million.
[6] Includes capital expenditures in Nigeria of $63 million.
Segmented net income for the three months ended September 30, 2011
Corporate Conventional Oil Sands and Total United North Other Kingdom America Countries In Situ Syncrude Other [1,2] Net Sales 756 112 185 146 185 15 1,399 Marketing and Other Income - 4 5 - 2 114 125 756 116 190 146 187 129 1,524 Less: Expenses Operating 106 34 39 97 73 7 356 Depreciation, Depletion, Amortization and Impairment 124 210 18 30 16 11 409 Transportation and Other 5 10 7 49 6 33 110 General and Administrative (7) 3 2 (1) 1 25 23 Exploration 15 17 27[3] - - - 59 Finance 6 5 - 1 1 46 59 Income (Loss) before Income Taxes 507 (163) 97 (30) 90 7 508 Less: Provision for Income Taxes 308[4] Net Income 200 Capital Expenditures 190 243 161[5] 90 34 11 729
[1]Includes results of operations in Yemen and Colombia.
[2]Includes Yemen Masila net sales of $138 million and net income before taxes of $52 million.
[3]Includes exploration activities primarily in Norway, Colombia and Poland.
[4]Includes UK current tax expense of $299 million.
[5]Includes capital expenditures in Nigeria of $135 million.
Segmented net income for the nine months ended September 30, 2012
Corporate Conventional Oil Sands and Total United North Other Kingdom America Countries In Situ Syncrude Other [1] Net Sales 3,028 284 479 534 491 34 4,850 Marketing and Other Income 29 6 - - 1 129 165 3,057 290 479 534 492 163 5,015 Less: Expenses Operating 324 127 89 352[2] 206 18 1,116 Depreciation, Depletion and Amortization 627 203 251 140 49 42 1,312 Transportation and Other 4 30 - 194 18 107 353 General and Administrative 25 92 44 43 1 259[3] 464 Exploration 41 205 17[4] 1 - - 264 Finance 18 11 1 2 6 187 225 Gain from Dispositions (2) (156) (7) (32) - - (197) Income (Loss) before Income Taxes 2,020 (222) 84 (166) 212 (450) 1,478 Less: Provision for Income Taxes 1,139[5] Net Income 339 Capital Expenditures 708 610 341[6] 493 149 30 2,331
[1]Includes results of operations in Nigeria, Yemen and Colombia.
[2]Includes Long Lake turnaround costs of $49 million.
[3]Includes non-cash stock-based compensation expense of $132 million.
[4] Includes exploration activities primarily in Colombia and Poland, and recovery of previously expensed exploration costs in Norway.
[5] Includes UK current tax expense of $1,134 million.
[6] Includes capital expenditures in Nigeria of $250 million.
Segmented net income for the nine months ended September 30, 2011
Corporate Conventional Oil Sands and Total United North Other Kingdom America Countries In Situ Syncrude Other [1,2] Net Sales 2,482 379 599 449 555 40 4,504 Marketing and Other Income 9 36 12 - 3 194 254 2,491 415 611 449 558 234 4,758 Less: Expenses Operating 265 110 109 331 223 22 1,060 Depreciation, Depletion, Amortization and Impairment 439 431 66 95 46 37 1,114 Transportation and Other 5 25 23 118 18 100 289 General and Administrative (17) 55 25 12 1 128 204 Exploration 32 117 127[3] 2 - - 278 Finance 16 13 1 2 4 157 193 Loss on Debt Redemption - - - - - 91 91 Gain from Dispositions (8) - - - - (4) (12) Income (Loss) before Income Taxes 1,759 (336) 260 (111) 266 (297) 1,541 Less: Provision for Income Taxes 1,189[4] Income from Continuing Operations 352 Add: Net Income from Discontinued Operations 302 Net Income 654 Capital Expenditures 368 485 478[5] 310 80 37 1,758
[1]Includes results of operations in Yemen and Colombia.
[2]Includes Yemen Masila net sales of $453 million and net income before taxes of $192 million.
[3]Includes exploration activities primarily in Norway, Colombia and Poland.
[4]Includes UK current tax expense of $1,047 million.
[5]Includes capital expenditures in Nigeria of $349 million.
Segmented assets as at September 30, 2012
Corporate Conventional Oil Sands and Total United North Other Kingdom America Countries In Situ Syncrude Other Total Assets 5,039 2,913 2,250 6,243 1,518 2,388[1] 20,351 Property, Plant and Equipment Cost 7,534 6,514 2,799 6,407 1,878 679 25,811 Less: Accumulated DD&A 4,127 4,131 878 330 456 427 10,349 Net Book Value 3,407 2,383[2] 1,921[3] 6,077[4] 1,422 252 15,462
[1]Includes cash of $1,039 million, and Energy Marketing accounts receivable, current derivative assets and inventory of $835 million.
[2]Includes net book value of $827 million associated with our Canadian shale gas operations.
[3]Includes net book value of $1,774 million related to our Usan development, offshore Nigeria.
[4]Includes net book value of $5,228 million for Long Lake Phase 1 and $849 million for future phases of our in situ oil sands projects.
Segmented assets as at December 31, 2011
Corporate Conventional Oil Sands and Total United North Other Kingdom America Countries In Situ Syncrude Other Total Assets 4,817 3,403 2,138 5,881 1,423 2,406[1] 20,068 Property, Plant and Equipment Cost 7,103 7,256 2,566 5,915 1,733 649 25,222 Less: Accumulated DD&A 3,707 4,299 648 205 411 381 9,651 Net Book Value 3,396 2,957[2] 1,918[3] 5,710[4] 1,322 268 15,571
[1]Includes cash of $453 million, and Energy Marketing accounts receivable, current derivative assets and inventory of $1,449 million.
[2]Includes net book value of $1,293 million associated with our Canadian shale gas operations.
[3]Includes net book value of $1,821 million related to our Usan development, offshore Nigeria.
[4]Includes net book value of $5,050 million for Long Lake Phase 1 and $660 million for future phases of our in situ oil sands projects.
For further information:
For investor relations inquiries, please contact:
Janet Craig
Vice President, Investor Relations
+1-(403)-699-4230
For media and general inquiries, please contact:
Pierre Alvarez
Vice President, Corporate Relations
+1-(403)-699-5202
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
http://www.nexeninc.com
