Nexen Announces Continued Progress on Strategic Initiatives & Solid Second Quarter Results
CALGARY, Alberta, July 19, 2012 /PRNewswire/ --
- Performance at Buzzard & Usan Drives Increased Production and Cash Flow
Nexen Inc. (TSX: NXY) (NYSE: NXY) today reported second quarter 2012 operating and financial results and provided an update on strategic priorities.
Production volumes averaged 213,000 barrels of oil equivalent per day (boe/d), a 5% increase from the first quarter. These volumes reflected the ramp-up of our Usan project offshore West Africa and solid performance from our UK assets, in particular the Buzzard platform. Cash flow from operations was up 6% to $707 million ($1.34/share) as we recognized the first cash flow from Usan and continued to benefit from our exposure to Brent-priced oil and strong cash netbacks. Net income decreased 36% from the prior quarter to $109 million ($0.20/share) primarily due to the previously announced unsuccessful Kakuna exploration well in the Gulf of Mexico.
We continue to make good progress on several of our strategic priorities:
- Buzzard operations were very strong; the facility produced 194,000 boe/d (84,000 boe/d net to Nexen) with a production efficiency of 88%, which exceeded our target of 85%.
- Usan continues to ramp-up and is currently producing over 100,000 barrels per day (bbls/d) (20,000 bbls/d net to Nexen) from the initial production wells.
- In the Gulf of Mexico, we continue to be excited by our success at Appomattox. We recently completed a successful appraisal well in the south fault block of the structure and the preliminary indications are that we are near the upper end of our expectations. Next, we plan on drilling a sidetrack to test additional resource potential in the northwest fault block.
- We also continue to progress our exploration program elsewhere, with drilling operations underway on the North Uist well in the UK North Sea and the Owowo West well, offshore West Africa.
- We achieved first production from pad 12 at Long Lake and began steaming pad 13 ahead of expectations; these pads are expected to produce 11,000-17,000 bbls/d of gross bitumen production following an 18 to 24 month ramp-up.
"I'm pleased that we continue to make significant progress against our milestones and that we've generated solid financial results over the past few quarters," said Kevin Reinhart, Nexen's interim President & CEO. "A renewed focus on operational excellence has allowed us to meet our production guidance again this quarter, and our growth plans are also advancing, with important progress at Long Lake, ongoing success at Appomattox and a couple of exciting exploration wells underway."
Operational Update
Conventional
Offshore West Africa - Oil production from Usan started February 24 on block OML-138, offshore Nigeria. Seven wells are now on-stream and since late April, production rates have averaged between 100,000 and 110,000 bbls/d (20,000-22,000 bbls/d net to Nexen). We expect to bring on additional producing wells later this year.
In July, we spudded an exploration well at Owowo West on block OPL-223 and expect to reach target depth there this fall. This well is in close proximity to our oil discovery at Owowo South B.
UKNorth Sea - Buzzard production efficiency was strong in the second quarter at 88%, calculated using an assumed maximum production rate of 220,000 boe/d. This exceeds our target of 85% efficiency, excluding planned downtime.
We plan to begin the scheduled major vessel inspection and turnaround at Buzzard in the first week of September. Production will be shut-in for several weeks as the work is completed; the facility is expected to return to full rates by mid-October.
We recently drilled a successful appraisal well in the Northern Terrace area of the Buzzard field. We are currently testing our discovery there and plan to sidetrack to assess the resource size.
At Telford, we saw very good rates from the TAC tieback in the second half of the quarter as we worked through minor facility issues encountered during start-up.
The Golden Eagle development continues to progress towards first oil in late 2014. The fabrication of the platform facilities is well underway; construction is on time and on budget.
Drilling is underway on our North Uist exploration prospect, which is located to the west of the Shetland Islands. Results from the BP-operated well are expected in the third quarter.
Gulf of Mexico - Our top priority in the Gulf of Mexico is continuing our exploration and appraisal program in the Norphlet play along with our partner, Shell Gulf of Mexico Inc.
To date, we have booked 65 million barrels of probable reserves in the south fault block of the Appomattox structure and added 50 million barrels of net contingent resource in the northeast fault block. We further delineated the south fault block during the second quarter with an appraisal well that encountered over 400 feet of net true vertical thickness oil pay and confirmed excellent reservoir quality. This well came in at the high end of our expectations and as a result, it could have a positive impact on our probable reserves.
We have five more exploration and appraisal targets in the Norphlet play that we plan to test over the next twelve months, including:
- A sidetrack from the recently completed appraisal well to test incremental resource potential in the northwest fault block of the Appomattox structure.
- An exploration well targeting a structure between Appomattox and our prior discovery at Vicksburg.
- A sidetrack from that well to further appraise the northeast fault block.
- Two nearby exploration wells at Petersburg and Rydberg.
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 interests are held by Shell, who is the operator.
Oil Sands
LongLake - Production from Long Lake was 33,700 bbls/d (gross) at a steam-oil-ratio of 5.0. Production was down slightly from 34,500 bbls/d in the first quarter as growth from pad 11 was offset by steam outages and well downtime, primarily during April. Production in May and June averaged 35,400 bbls/d (gross).
At pad 11, recent weekly averages have been about 6,000 bbls/d and we expect those rates to continue to increase going forward.
At pad 12, we are currently producing from four of the nine wells. The remaining wells are expected to be converted from circulation to production over the next few weeks. Pad 12 started production ahead of schedule due to new completion techniques and processes that will now be standard for future wells. The nine wells on pad 13 also began steaming ahead of schedule, primarily as a result of the efficiency of steam utilization on the pad 12 start-up.
A major turnaround beginning in mid-August will result in lower third quarter production rates compared to the first and second quarters of this year. Due to the turnaround, we expect approximately three weeks of SAGD downtime and six weeks of upgrader downtime.
Once the turnaround has been completed, we expect production to resume an upward trend. Steam injection is currently at record levels of about 190,000 bbls/d; we are directing this steam to the best available resource. We expect our year-end exit rate to be strong with pad 11 growth, the ramp-up of pads 12 and 13, and improved facility operations following the turnaround. We also have a few infill wells and re-drills that will start to contribute to production in the fourth quarter.
Upgrader yield (PSC[TM] barrels per barrel of bitumen) was 74% and facility on-stream time (percent of available bitumen processed) was 90%. Per-barrel operating costs were consistent with the prior quarter. Following the turnaround, we expect operating costs to decrease on a per-barrel basis as production increases. Lower oil prices and production resulted in a reduction in cash flow from the prior quarter.
Long Lake Quarterly Operating Metrics
Unit
Bitumen Steam Operating Cash Realized
Production (Gross) Injection (Gross) Cost[1] Flow Price
(bbls/d) (bbls/d) ($/bbl) ($ millions) ($/bbl)
2012
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
1. Unit operating costs and realized prices are before royalties and
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 costs.
We continue to make good progress towards filling the upgrader with additional wells in good-quality resource. We expect to begin drilling on pads 14, 15 and Kinosis 1A over the next several weeks. Together with the existing producing wells, we anticipate these wells will allow us to fill the upgrader over the next few years:
Number of Expected Peak
Wells Rates Timing
bbls/d
Pads 12 & Ramp-up over next 18-24
13 18 11,000 - 17,000 months
Pads 14 & Steam in second half of
15 11 4,000 - 7,000 2013
Kinosis 1A 29 15,000 - 25,000 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 INPEX and JGC is now expected to close before the end of July. All conditions of the transaction are expected to be met next week.
We are finalizing the completion activities on an 18-well pad in the Horn River. The pad is slated to come on-stream in the fourth quarter, concurrent with the facility expansion which will increase our production capacity to about 175 million cubic feet per day (mmcf/d) from approximately 50 mmcf/d. Lease earning activities are also commencing on our Liard acreage. Nexen and INPEX plan to develop our significant shale gas resource as economic conditions permit. We have also agreed to jointly investigate the feasibility of LNG export opportunities.
Production Summary
Average Daily Quarterly Average Daily Quarterly
Production before Royalties Production after Royalties
Crude Oil,
NGLs and
Natural
Gas
(mboe/d) Q2 2012 Q1 2012 Q2 2011 Q2 2012 Q1 2012 Q2 2011
UK -
Buzzard 84 82 49 84 82 49
UK - Other 30 29 35 30 28 35
Canada -
In Situ 22 22 18 20 21 17
Canada -
Oil & Gas 20 22 20 20 21 19
West
Africa 20 3 - 18 2 -
Canada -
Syncrude 17 21 20 17 19 18
United
States 14 16 25 13 15 22
Other
Countries 6 7 37 5 4 20
Total 213 202 204 207 192 180
Production increased 5% from the first quarter on a before-royalties basis and 8% on an after-royalties basis. The increase was primarily driven by the ramp-up of Usan and good performance from the Buzzard field. Those increases were offset by a longer than expected turnaround at Syncrude and lower rates at Longhorn in the Gulf of Mexico.
Guidance Update
Production of 213,000 boe/d met our guidance of 190,000 to 235,000 boe/d.
We are on-track to meet our third and fourth quarter production guidance, with Buzzard, Usan and Long Lake continuing to be the critical drivers of our guidance ranges.
Average Daily Production before Royalties
Crude
Oil, NGLs
and Q2
Natural Q1 Q2 2012 2012
Gas 2012 2012 Prior Q3 2012 Q4 2012 Annual
(mboe/d) Actual Actual Est. Estimate Estimate Estimate
UK -
Buzzard 82 84 75-95 50-60 75-95 70 - 85
UK -
Other 29 30 26-34 20-26 25-32 24 - 32
Canada -
In Situ 22 22 20-27 14-18 22-28 19 - 25
Canada -
Oil & Gas 22 20 15-18 15-17 15-20 15 - 19
Canada -
Syncrude 21 17 18-20 22-24 22-24 21 - 23
United
States 16 14 15-20 13-17 15-17 15 - 19
West
Africa 3 20 13-30 20-35 22-35 14 - 28
Other
Countries 7 6 2 2 2 2
202 213 ~190-235 ~160 -190 ~205-240 ~185 -220
At Buzzard, production will be primarily driven by production efficiency and the length of the turnaround. We expect that total planned shutdown days for the year will fall within our guidance of 29 to 42 days.
We also have downtime on the Scott platform planned for the third quarter. This will allow us to prepare the tie-in of the Rochelle facilities and complete regular platform maintenance. Rochelle is expected to be on-stream around the end of the year.
At Usan, the primary drivers of production will continue to be the timing of new well start-ups and overall well performance.
The primary factors affecting Long Lake production for the third quarter are well performance and the length of the planned turnaround. Our guidance reflects three weeks of production downtime related to the turnaround. In the fourth quarter, production should reflect facility improvements made during the turnaround as well as growing production from pads 11, 12 and 13.
Financial Results
Three Months Ended
Jun. 30 Mar. 31 Jun. 30
(Cdn$ millions, unless noted) 2012 2012 2011
Brent (US$/bbl) 108.66 119.13 117.36
WTI (US$/bbl) 93.49 102.93 102.56
NYMEX natural gas (US$/mmbtu) 2.35 2.51 4.37
Nexen Average Realized Oil & Gas Price ($/boe) 88.65 94.67 95.31
Cash netback ($/boe)[1] 44.51 45.81 42.38
Average Daily Production (mboe/d)
Before Royalties 213 202 204
After Royalties 207 192 180
Cash flow from operations[2 ] 707 670 598
Per common share ($/share) 1.34 1.27 1.13
Net income 109 171 252
Per common share ($/share) 0.20 0.32 0.48
Capital investment[3] 743 757 530
Net debt[4] 3,136 3,449 2,838
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. 10.
3. Includes geological and geophysical
expenditures.
4. Net debt is defined as long-term debt and
short-term borrowings less cash and cash
equivalents.
The second quarter financial results were strong, as the contribution from Usan and higher production volumes more than offset lower oil prices. Cash netbacks were fairly consistent with the first quarter as growth in our high-netback Usan production offset lower oil prices. This, combined with higher production, resulted in cash flow from operations increasing 6% compared to the prior quarter.
We continue to realize financial benefits from shipping oil off the west coast of Canada under the long-term contract we secured at the beginning of this year. During the quarter, our export capacity to the west coast of Canada generated approximately $34 million of incremental cash flow, a benefit which we expect to continue as long as Brent trades at a premium to North American crudes. Year-to-date, we have generated more than $70 million of cash flow from this source.
Net income declined to $109 million from $171 million in the first quarter due to the charge for the previously announced unsuccessful Kakuna exploration well.
Net debt decreased slightly compared to the first quarter. We expect to receive cash from our shale gas joint venture in the third quarter. This may be partially offset by capital expenditures exceeding cash flow, depending on oil prices.
Quarterly Dividends
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable October 1, 2012, to shareholders of record on September 10, 2012.
The Board has also declared the quarterly dividend on our Series 2 Preferred Shares of $0.3125 per share payable September 30, 2012 to shareholders of record on September 10, 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 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.
Earnings Conference Call
Nexen will discuss our 2012 second quarter financial results in a conference call on Thursday, July 19, 2012 at 7:00 am Mountain Time (9:00 am Eastern Time).
Kevin Reinhart, interim President and CEO, and Una Power, Senior Vice President and interim CFO, will discuss the financial and operating results as well as Nexen's business strategy and future expectations.
Conference Call Details:
Date: Thursday, July 19, 2012
Time: 7:00 am Mountain Time (9:00 am Eastern Time)
To listen to the conference call, please call one of the following:
+1(647)427-7450 (Toronto)
+1(888)231-8191 (North American toll-free)
0(800)051-7107 (UK toll-free)
We invite you to visit our website at http://www.nexeninc.com/2012q2 to listen to a live webcast of the conference call. Supplementary slides will also be available on our website.
A replay of the call will be available for two weeks starting at 10:00 am Mountain Time, July 19 by calling (416) 849-0833 (Toronto) or (855) 859-2056 (toll-free), passcode 94675938.
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; 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; 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; 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
Three Months Ended Six Months Ended
March
June 30 31 June 30 June 30 June 30
(Cdn$ millions, except per-share
amounts) 2012 2012 2011 2012 2011
Net Sales [1] 1,659 1,696 1,507 3,355 3,105
Cash Flow from Operations [1] 707 670 598 1,377 1,267
Per Common Share, Basic
($/share) 1.34 1.27 1.13 2.60 2.40
Per Common Share, Diluted
($/share) 1.28 1.22 1.10 2.50 2.34
Net Income [1] 109 171 252 280 454
Per Common Share, Basic
($/share) 0.20 0.32 0.48 0.52 0.86
Capital Investment [2] 743 757 530 1,500 1,029
Net Debt [3] 3,136 3,449 2,838 3,136 2,838
Common Shares Outstanding
(millions of shares) 529.3 528.9 527.0 529.3 527.0
[1] Includes results of discontinued operations. See Note 23 of our 2011 Annual Consolidated Financial Statements.
[2] Includes oil and gas development, exploration, and expenditures for other property, plant and equipment.
[3] Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents.
Cash Flow from Operations [1]
Three Months Ended Six Months Ended
March
June 30 31 June 30 June 30 June 30
(Cdn$ millions) 2012 2012 2011 2012 2011
Conventional Oil & Gas
United Kingdom 919 1,065 699 1,984 1,586
North America 15 38 91 53 156
Other Countries 165 19 173 184 311
Oil Sands
In Situ 4 18 6 22 (13)
Syncrude 70 91 103 161 210
1,173 1,231 1,072 2,404 2,250
Interest, Marketing and Other
Corporate Items [2] (70) (81) (90) (151) (175)
Income Taxes (396) (480) (384) (876) (808)
Cash Flow from Operations 707 670 598 1,377 1,267
[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 Six Months Ended
March
June 30 31 June 30 June 30 June 30
(Cdn$ millions) 2012 2012 2011 2012 2011
Cash Flow from Operating
Activities 1,159 508 1,020 1,667 1,750
Changes in Non-Cash Working
Capital (446) 146 (419) (300) (485)
Other 6 28 5 34 18
Impact of Annual Crude Oil Put
Options (12) (12) (8) (24) (16)
Cash Flow from Operations 707 670 598 1,377 1,267
Weighted Average Number of Common
Shares Outstanding, Basic
(millions of shares) 529 529 527 529 527
Cash Flow from Operations Per
Common
Share, Basic ($/share) 1.34 1.27 1.13 2.60 2.40
Cash Flow from Operations,
Diluted 713 676 604 1,390 1,279
Weighted Average Number of Common
Shares Outstanding, Diluted
(millions of shares) 556 553 547 555 546
Cash Flow from Operations Per
Common
Share, Diluted ($/share) 1.28 1.22 1.10 2.50 2.34
[2] 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 Six Months Ended
June 30 March 31 June 30 June 30 June 30
(mboe/d) 2012 2012 2011 2012 2011
Conventional Oil and Gas
United Kingdom 114.2 110.9 83.8 112.5 93.3
North America [2] 34.4 38.1 45.6 36.3 47.2
Other Countries [3] 25.5 9.5 36.5 17.5 38.2
174.1 158.5 165.9 166.3 178.7
Oil Sands
Long Lake Bitumen [4] 21.9 22.4 18.1 22.2 17.4
Syncrude 17.2 21.3 20.4 19.3 21.8
39.1 43.7 38.5 41.5 39.2
Total Production 213.2 202.2 204.4 207.8 217.9
Total Crude Oil and Liquids
(mbbls/d) 178.7 167.4 161.5 173.1 173.7
Total Natural Gas (mmcf/d) 207 209 257 208 265
Production Volumes (after royalties)
Three Months Ended Six Months Ended
June 30 March 31 June 30 June 30 June 30
(mboe/d) 2012 2012 2011 2012 2011
Conventional Oil and Gas
United Kingdom 113.7 110.4 83.5 112.0 93.1
North America [2] 33.1 35.4 41.6 34.3 42.9
Other Countries [3] 22.9 6.5 20.4 14.7 21.3
169.7 152.3 145.5 161.0 157.3
Oil Sands
Long Lake Bitumen [4] 20.4 21.0 16.9 20.7 16.3
Syncrude 16.9 18.8 17.8 17.9 20.1
37.3 39.8 34.7 38.6 36.4
Total Production 207.0 192.1 180.2 199.6 193.7
Total Crude Oil and Liquids
(mbbls/d) 173.2 159.2 140.4 166.3 152.9
Total Natural Gas (mmcf/d) 203 197 239 200 245
[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] Other Countries consists of production in Nigeria, Yemen and Colombia.
[4] We report Long Lake bitumen as production.
Nexen Inc.
Oil and Gas Prices and Cash Netback [1]
Total
Quarters - 2012 Quarters - 2011 Year
(all dollar
amounts in Cdn$
unless noted) 1st 2nd 3rd 4th 1st 2nd 3rd 4th 2011
PRICES:
Brent Crude Oil
(US$/bbl) 119.13 108.66 104.97 117.36 113.47 109.31 111.28
WTI Crude Oil
(US$/bbl) 102.93 93.49 94.10 102.56 89.76 94.06 95.12
Nexen Average -
Oil (Cdn$/bbl) 111.62 102.21 98.37 110.28 103.98 108.44 105.21
NYMEX Natural Gas
(US$/mmbtu) 2.51 2.35 4.20 4.37 4.06 3.48 4.03
AECO Natural Gas
(Cdn$/mcf) 2.39 1.74 3.58 3.54 3.53 3.29 3.48
Nexen Average -
Gas (Cdn$/mcf) 3.13 2.58 4.51 4.75 4.36 3.63 4.31
NETBACKS [1]:
United Kingdom
Crude Oil:
Sales (mbbls/d) 106.9 105.3 104.2 73.3 75.2 92.7 86.3
Price Received
($/bbl) 118.12 105.82 99.97 110.67 107.58 110.46 106.76
Natural Gas:
Sales (mmcf/d) 33 31 36 37 26 22 30
Price Received
($/mcf) 7.83 6.64 7.29 8.20 7.28 6.52 7.42
Total Sales
Volume (mboe/d) 112.3 110.4 110.2 79.5 79.5 96.4 91.3
Price Received
($/boe) 114.65 102.74 96.91 105.87 104.13 107.70 103.32
Royalties & Other 0.51 0.55 - 0.11 0.82 0.54 0.36
Operating Costs 10.14 10.90 9.85 8.48 14.46 9.99 10.60
In-country Taxes 45.41 38.84 42.46 42.76 41.00 43.24 42.41
Netback 58.59 52.45 44.60 54.52 47.85 53.93 49.95
Oil Sands - In
Situ [2]
Sales (mbbls/d) 17.8 16.5 12.9 14.3 11.8 16.7 13.9
Price Received
($/bbl) 94.45 86.58 89.82 108.78 94.15 97.28 98.33
Royalties & Other 4.79 6.10 3.58 6.05 5.07 5.29 5.05
Operating Costs 68.89 69.95 89.43 95.34 85.42 67.41 83.44
Netback [2] 20.77 10.53 (3.19) 7.39 3.66 24.58 9.84
Oil Sands -
Syncrude
Sales (mbbls/d) 21.3 17.2 23.2 20.4 21.6 18.2 20.8
Price Received
($/bbl) 92.54 89.85 94.60 111.79 97.65 104.32 101.73
Royalties & Other 11.25 (3.03) 4.30 13.82 4.65 10.59 8.10
Operating Costs 31.36 44.96 36.11 39.98 37.10 38.24 37.78
Netback 49.93 47.92 54.19 57.99 55.90 55.49 55.85
United States
Crude Oil:
Sales (mbbls/d) 8.0 7.3 9.2 8.9 7.7 7.2 8.2
Price Received
($/bbl) 108.40 102.19 91.39 101.89 96.00 110.89 99.65
Natural Gas:
Sales (mmcf/d) 50 41 103 96 81 66 86
Price Received
($/mcf) 2.67 2.19 4.36 4.42 4.27 3.59 4.21
Total Sales
Volume (mboe/d) 16.3 14.1 26.3 24.9 21.2 18.2 22.6
Price Received
($/boe) 61.33 58.84 48.91 53.56 50.72 57.27 52.31
Royalties & Other 6.02 6.12 5.65 6.11 5.63 3.31 5.30
Operating Costs 17.29 17.87 10.43 10.72 11.18 16.73 11.96
Netback 38.02 34.85 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.
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 4th 1st 2nd 3rd 4th 2011
Canada - Natural
Gas [2]
Sales (mmcf/d) 131 120 97 85 79 112 93
Price Received
($/mcf) 2.12 1.67 3.65 3.62 3.51 3.08 3.44
Royalties & Other 0.08 (0.05) 0.28 0.24 0.27 0.17 0.23
Operating Costs 1.58 1.62 1.70 1.54 1.65 1.70 1.65
Netback 0.46 0.10 1.67 1.84 1.59 1.21 1.56
Other Countries
[3]
Sales (mbbls/d) 5.4 27.0 36.7 41.0 33.5 29.4 35.1
Price Received
($/bbl) 119.61 105.59 101.17 111.56 107.64 111.10 107.85
Royalties & Other 48.76 17.27 44.95 50.38 47.54 43.83 46.92
Operating Costs 13.02 17.70 10.62 9.23 12.97 19.89 12.73
In-country Taxes 9.31 2.50 12.81 15.58 14.71 13.27 14.17
Netback 48.52 68.12 32.79 36.37 32.42 34.11 34.03
Company-Wide
Oil and Gas Sales
(mboe/d) 195.0 205.2 225.5 194.3 180.7 197.6 199.2
Price Received
($/boe) 94.67 88.65 85.98 95.31 91.06 94.11 91.46
Royalties & Other 3.87 3.19 8.74 13.47 10.83 8.62 10.34
Operating & Other
Costs 18.56 19.74 17.32 18.68 20.80 19.56 19.00
In-country Taxes 26.43 21.21 22.84 20.78 20.76 23.08 21.92
Netback 45.81 44.51 37.08 42.38 38.67 42.85 40.20
[1] Netbacks are defined as average sales price less royalties and other, operating costs and in-country taxes.
[2] Includes Canadian conventional, CBM and shale gas activities. Shale gas was included beginning in the fourth quarter of 2011 when it became commercial.
[3] Other Countries relates to Yemen, Colombia and West Africa.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Income
For the Three and Six Months Ended June 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except per-share amounts) 2012 2011 2012 2011
Revenues and Other Income
Net Sales 1,659 1,507 3,355 3,105
Marketing and Other Income (Note 8) 128 95 158 141
1,787 1,602 3,513 3,246
Expenses
Operating 376 341 715 704
Depreciation, Depletion and Amortization 488 335 885 705
Transportation and Other 105 112 225 179
General and Administrative 115 76 241 181
Exploration 155 93 215 219
Finance (Note 5) 81 60 145 134
Loss on Debt Redemption and Repurchase - 1 - 91
Gain from Dispositions (Note 10) (45) - (45) -
1,275 1,018 2,381 2,213
Income from Continuing Operations before
Provision
for Income Taxes 512 584 1,132 1,033
Provision for (Recovery of) Income Taxes
Current 396 384 876 808
Deferred 7 (52) (24) 73
403 332 852 881
Net Income from Continuing Operations 109 252 280 152
Net Income from Discontinued Operations,
Net of Tax - - - 302
Net Income Attributable to Nexen Inc.
Shareholders 109 252 280 454
Earnings Per Common Share from Continuing
Operations ($/share) (Note 6)
Basic 0.20 0.48 0.52 0.29
Diluted 0.19 0.45 0.52 0.27
Earnings Per Common Share ($/share) (Note
6)
Basic 0.20 0.48 0.52 0.86
Diluted 0.19 0.45 0.52 0.84
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Balance Sheet
June 30 December 31
(Cdn$ millions) 2012 2011
Assets
Current Assets
Cash and Cash Equivalents 1,255 845
Restricted Cash 102 45
Accounts Receivable 1,685 2,247
Derivative Contracts 155 119
Inventories and Supplies 283 320
Other 137 115
Total Current Assets 3,617 3,691
Non-Current Assets
Property, Plant and Equipment (Note 3) 16,030 15,571
Goodwill 292 291
Deferred Income Tax Assets 442 338
Derivative Contracts 5 25
Other Long-Term Assets 112 152
Total Assets 20,498 20,068
Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities 2,285 2,867
Income Taxes Payable 849 458
Derivative Contracts 105 103
Total Current Liabilities 3,239 3,428
Non-Current Liabilities
Long-Term Debt 4,391 4,383
Deferred Income Tax Liabilities 1,561 1,488
Asset Retirement Obligations 2,020 2,010
Derivative Contracts 5 24
Other Long-Term Liabilities 443 362
Equity (Note 6)
Share Capital
Common Shares 1,183 1,157
Preferred Shares 195 -
Retained Earnings 7,435 7,211
Cumulative Translation Adjustment 26 5
Total Equity 8,839 8,373
Total Liabilities and Equity 20,498 20,068
See accompanying notes to Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Cash Flows
For the Three and Six Months Ended June 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2012 2011 2012 2011
Operating Activities
Net Income from Continuing Operations 109 252 280 152
Net Income from Discontinued Operations - - - 302
Charges and Credits to Income not
Involving Cash (Note 9) 455 261 906 610
Exploration Expense 155 93 215 219
Changes in Non-Cash Working Capital (Note
9) 446 419 300 485
Other (6) (5) (34) (18)
1,159 1,020 1,667 1,750
Financing Activities
Repayment of Long-Term Debt - (525) - (871)
Issue of Preferred Shares - - 195 -
Dividends Paid on Common Shares (27) (26) (53) (52)
Issue of Common Shares 8 8 26 31
Other (4) (6) (6) 1
(23) (549) 162 (891)
Investing Activities
Capital Expenditures
Exploration, Evaluation and Development (718) (516) (1,454) (992)
Corporate and Other (25) (20) (46) (37)
Proceeds from Dispositions (Note 10) 46 12 53 474
Changes in Restricted Cash (82) (2) (56) (11)
Changes in Non-Cash Working Capital (Note
9) 23 31 65 115
Other (4) (23) 5 (75)
(760) (518) (1,433) (526)
Effect of Exchange Rate Changes on Cash
and Cash Equivalents 23 (15) 14 (26)
Increase (Decrease) in Cash and Cash
Equivalents 399 (62) 410 307
Cash and Cash Equivalents - Beginning of
Period 856 1,374 845 1,005
Cash and Cash Equivalents - End of Period
[1] 1,255 1,312 1,255 1,312
[1] Cash and cash equivalents at June 30, 2012 consists of cash of $319 million and short-term investments of $936 million (June 30, 2011 - cash of $218 million and short-term investments of $1,094 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Changes in Equity
For the Three and Six Months Ended June 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2012 2011 2012 2011
Share Capital
Common Shares, Beginning of Period 1,175 1,134 1,157 1,111
Issue of Common Shares 8 8 26 31
Common Shares, Balance at End of Period 1,183 1,142 1,183 1,142
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 7,356 6,868 7,211 6,692
Net Income Attributable to Nexen Inc.
Shareholders 109 252 280 454
Dividends on Common and Preferred Shares
(Note 6) (30) (26) (56) (52)
Balance at End of Period 7,435 7,094 7,435 7,094
Cumulative Translation Adjustment,
Beginning of Period (8) (48) 5 (37)
Currency Translation Adjustment 23 (7) 5 (18)
Realized Translation Adjustments [1] 11 - 16 -
Balance at End of Period 26 (55) 26 (55)
[1] Net of income tax recovery for the three months ended June 30, 2012 of $5 million (2011 - net of income tax expense of $11 million) and net of income tax recovery for the six months ended June 30, 2012 of $7 million (2011 - net of income tax expense of $20 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Comprehensive Income
For the Three and Six Months Ended June 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2012 2011 2012 2011
Net Income Attributable to Nexen Inc.
Shareholders 109 252 280 454
Other Comprehensive Income (Loss):
Currency Translation Adjustment
Net Translation Gains (Losses) of Foreign
Operations 98 (35) 14 (139)
Net Translation Gains (Losses) on
US$-Denominated Debt Hedging of Foreign
Operations [1] (75) 28 (9) 121
Total Currency Translation Adjustment 23 (7) 5 (18)
Total Comprehensive Income 132 245 285 436
[1] Net of income tax recovery for the three months ended June 30, 2012 of $10 million (2011 - net of income tax expense of $4 million) and net of income tax recovery for the six months ended June 30, 2012 of $1 million (2011 - net of income tax expense of $17 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cdn$ 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 six months ended June 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.
The Unaudited Condensed Consolidated Financial Statements were authorized for issue by Nexen's Board of Directors on July 18, 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)
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 390 335 729 46 1,500
Disposals/Derecognitions (9) - (74) (15) (98)
Transfers [1] - (1,862) 1,862 - -
Exploration Expense (215) - - - (215)
Other (17) - 51 17 51
Effect of Changes in
Exchange Rate 5 1 40 1 47
As at June 30, 2012 2,360 821 22,440 886 26,507
Accumulated
Depreciation, Depletion
& Amortization (DD&A)
As at December 31, 2011 368 - 8,860 423 9,651
DD&A 33 - 809 43 885
Disposals/Derecognitions (8) - (74) (12) (94)
Other - - (8) 17 9
Effect of Changes in
Exchange Rate - - 26 - 26
As at June 30, 2012 393 - 9,613 471 10,477
Net Book Value
As at December 31, 2011 1,838 2,347 10,972 414 15,571
As at June 30, 2012 1,967 821 12,827 415 16,030
[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 June 30, 2012 primarily include our developments in the UK North Sea.
4. LONG-TERM DEBT
During the three and six months ended June 30, 2012, we borrowed and repaid nil and $254 million on our term credit facilities, respectively. We recorded $85 million and $10 million, respectively, of unrealized foreign exchange losses on long-term debt in other comprehensive income.
We have undrawn, committed, unsecured term credit facilities of $3.8 billion, of which $700 million is available until 2014 and $3.1 billion is available until 2017. As at June 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 $21 million of these facilities to support outstanding letters of credit at June 30, 2012 (December 31, 2011-$17 million).
Nexen has uncommitted, unsecured credit facilities of approximately $214 million exclusively to support letters of credit. We utilized $3 million of these facilities to support outstanding letters of credit at June 30, 2012 (December 31, 2011-$4 million).
5. FINANCE EXPENSE
Three Months Six Months
Ended June 30 Ended June 30
2012 2011 2012 2011
Interest on Long-Term Debt 73 74 148 158
Accretion Expense Related to Asset
Retirement Obligations 13 12 26 23
Other Interest and Fees 7 3 12 10
Total 93 89 186 191
Less: Capitalized at 6.7% (2011 - 6.6%) (12) (29) (41) (57)
Total 81 60 145 134
Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings.
6. EQUITY
(a) Common Shares
Authorized share capital consists of an unlimited number of common shares of no par value. At June 30, 2012, there were 529,335,905 common shares outstanding (December 31, 2011-527,892,635 common shares).
(b) Preferred Shares
Authorized share capital consists of an unlimited number of Class A preferred shares of no par value, issuable in series. At June 30, 2012, there were 8,000,000 Cumulative Redeemable Class A Rate Reset Preferred Shares, Series 2 outstanding (December 31, 2011-nil).
(c) Earnings Per Common Share (EPS)
We calculate basic EPS using net income attributable to Nexen Inc. shareholders, adjusted for preferred share dividends and divided by the weighted-average number of common shares outstanding. We calculate diluted EPS in the same manner as basic, except we adjust basic earnings for the potential conversion of the subordinated debentures and potential exercise of outstanding tandem options for shares, if dilutive. We use the weighted-average number of diluted common shares outstanding in the denominator of our diluted EPS calculation.
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2012 2011 2012 2011
Net Income Attributable to Nexen Inc.
Shareholders 109 252 280 454
Preferred Share Dividends (2) - (3) -
Net Income Attributable to Nexen Inc.
Shareholders, Basic 107 252 277 454
Potential Tandem Options Exercises (7) (14) (3) (9)
Potential Conversion of Subordinated
Debentures - 6 13 12
Net Income Attributable to Nexen Inc.
Shareholders, Diluted 100 244 287 457
(millions of shares)
Weighted Average Number of Common Shares
Outstanding, Basic 529 527 529 527
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 - 20 26 19
Weighted Average Number of Common Shares
Outstanding, Diluted 529 547 555 546
In calculating the weighted-average number of diluted common shares outstanding and related earnings adjustments for the three and six months ended June 30, 2012, we excluded 14,910,152 and 14,879,437 tandem options, respectively (2011-15,068,347 and 15,210,923, respectively) because their exercise price was greater than the average common share market price in the quarter. During the three months ended June 30, 2012, the potential conversion of tandem options was the only dilutive instrument. During the six months ended June 30, 2012, and the three and six months ended June 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 $0.10 per common share, for the three and six months ended June 30, 2012 ($0.05 and $0.10 per common share for the respective periods ended June 30, 2011). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.
On July 18, 2012, the board of directors declared a quarterly dividend of $0.05 per common share, payable October 1, 2012 to the shareholders of record on September 10, 2012. Also, the board of directors declared a quarterly dividend of $0.3125 per preferred share, payable September 30, 2012 to the shareholders of record on September 10, 2012.
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 in the UK North Sea.
2012 2013 2014 2015 2016 Thereafter
Drilling Rig Commitments - 74 46 - - -
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.
8. MARKETING AND OTHER INCOME
Three Months Six Months
Ended June 30 Ended June 30
2012 2011 2012 2011
Marketing Revenue, Net 110 51 175 102
Foreign Exchange Gains (Losses) 12 6 (4) (16)
Change in Fair Value of Crude Oil Put
Options 2 - (34) (7)
Insurance Proceeds - 26 - 26
Other 4 12 21 36
Total 128 95 158 141
9. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Six Months
Ended June 30 Ended June 30
2012 2011 2012 2011
Depreciation, Depletion and Amortization 488 335 885 705
Gain from Dispositions (45) - (45) -
Change in Fair Value of Crude Oil Put
Options (2) - 34 7
Stock-Based Compensation (2) (29) 24 (2)
Foreign Exchange (8) (6) 8 17
Provision for (Recovery of) Deferred
Income Taxes 7 (52) (24) 73
Loss on Debt Redemption and Repurchase - 1 - 91
Non-Cash Items Included in Discontinued
Operations - - - (290)
Other 17 12 24 9
Total 455 261 906 610
(b) Changes in non-cash working capital
Three Months Six Months
Ended June 30 Ended June 30
2012 2011 2012 2011
Accounts Receivable 348 240 513 (134)
Inventories and Supplies 47 163 40 184
Other Current Assets (15) (17) (17) (9)
Accounts Payable and Accrued Liabilities (283) (248) (546) 169
Current Income Taxes Payable 372 312 375 390
Total 469 450 365 600
Relating to:
Operating Activities 446 419 300 485
Investing Activities 23 31 65 115
Total 469 450 365 600
(c) Other cash flow information
Three Months Six Months
Ended June 30 Ended June 30
2012 2011 2012 2011
Interest Paid 58 66 148 130
Income Taxes Paid 17 69 497 460
10. DISPOSITIONS
Asset Dispositions
Canadian Undeveloped Leases
During the quarter, we sold non-core leases in Canada for proceeds of $46 million and recognized a gain of $45 million.
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 June 30, 2012
Corporate
and
Conventional Oil Sands Other Total
United North Other In
Kingdom America Countries [1] Situ Syncrude
Net Sales 1,028 88 217 173 145 8 1,659
Marketing and
Other Income 3 - - - 1 124 128
1,031 88 217 173 146 132 1,787
Less: Expenses
Operating 109 41 43 107 70 6 376
Depreciation,
Depletion and
Amortization 224 72 112 51 16 13 488
Transportation
and Other 5 9 - 51 6 34 105
General and
Administrative 3 22 9 11 - 70 115
Exploration 19 139 (3) [2] - - - 155
Finance 6 4 1 - 2 68 81
Gain on
Dispositions - (13) - (32) - - (45)
Income (Loss)
before
Income Taxes 665 (186) 55 (15) 52 (59) 512
Less:
Provision for 403
Income Taxes [3]
Net Income 109
Capital
Expenditures 243 177 122 [4] 127 62 12 743
[1] Includes results of operations in Nigeria, Yemen and Colombia.
[2] Includes exploration activities primarily in Colombia and Poland, and recovery of previously expensed exploration costs in Norway.
[3] Includes UK current tax expense of $380 million.
[4] Includes capital expenditures in Nigeria of $91 million.
Segmented net income for the three months ended June 30, 2011
Corporate
and
Conventional Oil Sands Other Total
Other
United North Countries
Kingdom America [1, 2] In Situ Syncrude
Net Sales 764 134 229 188 181 11 1,507
Marketing and
Other Income 1 30 3 - 1 60 95
765 164 232 188 182 71 1,602
Less: Expenses
Operating 61 36 35 127 75 7 341
Depreciation,
Depletion and
Amortization 133 116 23 36 14 13 335
Transportation
and Other - 11 11 51 6 33 112
General and
Administrative 2 19 8 2 - 45 76
Exploration 13 41 37 [3] 2 - - 93
Finance 5 4 1 - 2 48 60
Loss on Debt
Redemption - - - - - 1 1
Income (Loss)
before
Income Taxes 551 (63) 117 (30) 85 (76) 584
Less: Provision
for Income 332
Taxes [4]
Net Income 252
Capital
Expenditures 104 123 171 [5] 91 27 14 530
[1] Includes results of operations in Yemen and Colombia.
[2] Includes Yemen Masila net sales of $169 million and net income before taxes of $78 million.
[3] Includes exploration activities primarily in Norway, Colombia and Poland.
[4] Includes UK current tax expense of $323 million.
[5] Includes capital expenditures in Nigeria of $114 million.
Segmented net income for the six months ended June 30, 2012
Corporate
and
Conventional Oil Sands Other Total
United North Other In
Kingdom America Countries [1] Situ Syncrude
Net Sales 2,194 194 251 391 303 22 3,355
Marketing and
Other Income 9 3 7 - 1 138 158
2,203 197 258 391 304 160 3,513
Less: Expenses
Operating 213 85 52 221 131 13 715
Depreciation,
Depletion and
Amortization 470 138 118 100 32 27 885
Transportation
and Other 5 16 - 128 12 64 225
General and
Administrative 8 46 18 22 - 147 241
Exploration 30 177 8 [2] - - - 215
Finance 12 8 1 1 4 119 145
Gain on
Dispositions - (13) - (32) - - (45)
Income (Loss)
before
Income Taxes 1,465 (260) 61 (49) 125 (210) 1,132
Less:
Provision for 852
Income Taxes [3]
Net Income 280
Capital
Expenditures 438 432 252 [4] 276 82 20 1,500
[1] Includes results of operations in Nigeria, Yemen and Colombia.
[2] Includes exploration activities primarily in Colombia and Poland, and recovery of previously expensed exploration costs in Norway.
[3] Includes UK current tax expense of $856 million.
[4] Includes capital expenditures in Nigeria of $187 million.
Segmented net income for the six months ended June 30, 2011
Corporate
and
Conventional Oil Sands Other Total
Other
United North Countries
Kingdom America [1, 2] In Situ Syncrude
Net Sales 1,726 267 414 303 370 25 3,105
Marketing and
Other Income 17 32 7 - 1 84 141
1,743 299 421 303 371 109 3,246
Less: Expenses
Operating 159 76 70 234 150 15 704
Depreciation,
Depletion and
Amortization 315 221 48 65 30 26 705
Transportation
and Other - 15 16 69 12 67 179
General and
Administrative (10) 52 23 13 - 103 181
Exploration 17 100 100 [3] 2 - - 219
Finance 10 8 1 1 3 111 134
Loss on Debt
Redemption - - - - - 91 91
Income (Loss)
before
Income Taxes 1,252 (173) 163 (81) 176 (304) 1,033
Less: Provision
for Income 881
Taxes [4]
Income from
Continuing
Operations 152
Add: Net Income
from
Discontinued
Operations 302
Net Income 454
Capital
Expenditures 178 242 317 [5] 220 46 26 1,029
[1] Includes results of operations in Yemen and Colombia.
[2] Includes Yemen Masila net sales of $315 million and net income before taxes of $135 million.
[3] Includes exploration activities primarily in Norway, Colombia and Poland.
[4] Includes UK current tax expense of $749 million.
[5] Includes capital expenditures in Nigeria of $214 million.
Segmented assets as at June 30, 2012
Corporate
and
Conventional Oil Sands Other Total
United North Other In
Kingdom America Countries Situ Syncrude
Total Assets 5,073 3,516 2,295 6,027 1,436 2,151 [1] 20,498
Property,
Plant and
Equipment
Cost 7,519 7,502 2,814 6,191 1,811 670 26,507
Less:
Accumulated
DD&A 4,122 4,418 783 301 439 414 10,477
5,890
Net Book Value 3,397 3,084 [2] 2,031 [3] [4] 1,372 256 16,030
[1] Includes cash of $667 million, and Energy Marketing accounts receivable, current derivative assets and inventory of $935 million.
[2] Includes net book value of $1,495 million associated with our Canadian shale gas operations.
[3] Includes net book value of $1,896 million related to our Usan development, offshore Nigeria.
[4] Includes net book value of $5,162 million for Long Lake Phase 1 and $728 million for future phases of our in situ oil sands projects.
Segmented assets as at December 31, 2011
Corporate
and
Conventional Oil Sands Other Total
United North Other In
Kingdom America Countries Situ Syncrude
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
5,710
Net Book Value 3,396 2,957 [2] 1,918 [3] [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
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