|
|
Nexen Reports Record Quarterly Cash Flow
CALGARY, ALBERTA--(Marketwire - July 12, 2007) -
Second Quarter Highlights:
- Record cash flow of $1.73 per share; earnings of $0.70 per share
- Production after royalties increases 9% over Q1 to 208,000 boe/d (253,000 boe/d before royalties)
- Buzzard reaching facility design rates of 200,000 boe/d (85,000 boe/d net)
- Steam injection ramping up at Long Lake-on track for bitumen production this fall and upgrader start up late in the year
Three Months Ended Six Months Ended
June 30 June 30
-------------------- --------------------
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 253 215 246 219
After Royalties 208 158 199 159
Net Sales 1,399 1,039 2,539 2,019
Cash Flow from Operations(2) 913 729 1,511 1,402
Per Common Share ($/share)(2,3) 1.73 1.39 2.87 2.68
Net Income 368 408 489 325
Per Common Share ($/share)(3) 0.70 0.78 0.93 0.62
Capital Expenditures(4) 819 876 1,630 1,629
----------------------------------------------------------------------------
(1) Production includes our share of Syncrude oil sands. US investors should
read the Cautionary Note to US Investors at the end of this release.
(2) For reconciliation of this non-GAAP measure see Cash Flow from
Operations on pg. 7.
(3) 2006 per share values have been adjusted to reflect the May 2007
two-for-one stock split.
(4) Includes business acquisitions in 2006.
Nexen delivered solid financial results in the second quarter with record cash flow of $913 million and net income of $368 million. These results reflect increasing production from the successful ramp up of Buzzard and strong commodity prices. While the price of West Texas Intermediate crude oil (WTI) was strong in the quarter, averaging US$65.03/bbl, the price of Brent crude was stronger, averaging US$68.76/bbl. This Brent premium to WTI of US$3.73/bbl for the quarter compares to a US$1.08/bbl discount in the second quarter of 2006. The WTI discount reflects excess supply of crude in the US Midwest due to high local storage levels at Cushing, Oklahoma, extensive refinery downtime and increased imports of Canadian crude. Since approximately 80% of our production is priced off Brent, the benefit we receive from strong Brent prices is substantial.
Our marketing group contributed $70 million to our cash flow for the quarter primarily from trading spreads related to natural gas, crude oil and power. So far this year, we have booked $71 million of cash flow from our marketing activities and we have an additional $45 million of gains on the increased value of our oil and gas marketing inventories and transportation assets that have not yet been booked. These gains can only be booked in the future when the inventories are sold and the transportation assets are used.
Exploration expense totaled $105 million ($60 million after tax) for the quarter. This includes seismic data acquisition and exploration expense related to drilling activity in Colombia, the UK North Sea and on the shelf in the Gulf of Mexico.
During the quarter, we purchased put options on approximately 100,000 bbls/d of crude oil production for calendar year 2008. These options establish a Dated Brent floor price of US$50/bbl on these volumes and were purchased for approximately US$23 million (US$0.63/bbl). These put options provide us with a continued base level of price protection without limiting our upside in a high price environment.
"The majority of our production is priced off Brent which is currently very strong," commented Charlie Fischer, Nexen's President and Chief Executive Officer. "With Buzzard production now approaching facility design rates, we are on track to generate record cash flow this year reflecting significant growth and value for our shareholders."
Oil and Gas Production
Production before Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q2 2007 Q1 2007 Q2 2007 Q1 2007
------------------------------------------------------ --------------------
Yemen 73 77 42 45
North Sea 88 58 88 58
Canada 37 38 30 30
United States 30 38 26 34
Other Countries 6 6 5 5
Syncrude 19 21 17 19
-------------------- --------------------
Total 253 238 208 191
-------------------- --------------------
Our second quarter production averaged 253,000 boe/d (208,000 boe/d after royalties) as the Buzzard field in the North Sea continued to ramp up to design rates. Buzzard contributed 68,000 boe/d to our quarterly volumes.
In the Gulf of Mexico, drilling and completion delays have caused initial production from our Wrigley and Aspen developments to slip into the third quarter. At Aspen, we experienced unexpected production downtime as a result of maintenance to third party processing facilities. At Syncrude, production was lower following the advancement of turnaround activity originally scheduled for late this year. With Buzzard producing at facility design rates, Syncrude back up to full capacity and incremental volumes from Wrigley and Aspen, we expect much stronger production volumes for the remainder of the year.
"The timing of several of our projects has slipped but this has not impacted project returns," stated Fischer. "As a result of these timing delays, we will likely be at or slightly below the lower end of our guidance range of 275,000 boe/d to 305,000 boe/d for the full year."
North Sea Update
At Buzzard, we currently have eight development wells on stream. The production ramp up to date has met our expectations and we have sufficient well deliverability to take advantage of additional processing capacity that may be available on the platform. The platform is designed to process up to 200,000 bbls/d of oil and 60 mmcf/d of gas.
"We are delighted with the performance of the Buzzard field as the pressure response we have seen indicates reservoir connectivity is outstanding," said Fischer. "With cash netbacks per barrel averaging 85% of the price of Brent, Buzzard's cash flow contribution is significant. For example, with Buzzard producing at full facility design rates, we expect it to generate approximately $1.6 billion of annual pre-tax cash flow, assuming WTI of US$50/bbl."
Elsewhere in the North Sea, we are evaluating development options for our Golden Eagle discovery. In addition we are drilling an appraisal well at Selkirk located on Block 22/22b. The pre-drill unrisked resource estimate is between 10 and 20 million boe. Results from this well are expected in the third quarter. We have a 38% operated working interest here. Additionally, we plan to drill an appraisal well at Bugle, and spud three exploration wells later this year.
Long Lake Project Update
At Long Lake, commissioning of our large steam generator units is underway. While we are experiencing delays in the start up of these units, all 81 SAGD well pairs (10 pads) are expected to be steaming by the end of August. As we circulate steam and heat up the reservoir to establish communication between the wells, we will start to produce bitumen. We expect bitumen production to ramp up to full rates over a 12 to 24 month period. While our initial steam-to-oil ratios will be high as we heat up the reservoir, we expect our steam-to-oil ratio to average approximately 3.0 over the project life.
Upgrader construction is approximately 90% complete and projected to start up late this year. Full production of premium synthetic crude oil is expected within 12 to 18 months of upgrader start up. Production capacity for the first phase of Long Lake is approximately 60,000 bbls/d (30,000 bbls/d net to Nexen) of premium synthetic crude. Our cost estimate for Phase 1 ranges from $5.0 to $5.3 billion ($2.5 to $2.65 billion net to Nexen).
"Long Lake is progressing well and we are committed to the safe and steady start up of all facilities," stated Fischer.
Phase 1 of Long Lake will develop approximately 10% of our 5.5 billion barrel recoverable resource using our patented process which significantly reduces our need to purchase natural gas, a key cost driver in competing technologies. This will result in a significant cost advantage for us. We plan to sequentially develop additional 60,000 bbls/d (30,000 bbls/d net to Nexen) phases using the same technology and design as Long Lake. The timing of Phase 2 sanctioning will depend on accumulating sufficient production history from Phase 1 and receiving additional clarity on fiscal and regulatory policies related to oil sands development and climate change.
Ettrick Development On Track for First Oil in 2008
Our Ettrick field development in the North Sea continues to progress well and is approximately 70% complete. The project will consist of three production wells and one water injector tied back to a leased floating production, storage and offloading vessel (FPSO). The FPSO is designed to handle 30,000 bbls/d of oil, 35 mmcf/d of gas and to re-inject 55,000 bbls/d of water. Production from the field is expected to commence in mid 2008 with our share averaging approximately 9,000 boe/d for the year. We have an 80% operated working interest.
Gulf of Mexico Update
At our Wrigley development on Mississippi Canyon Block 506, we began producing early in the third quarter. We expect production to quickly ramp up to 60 mmcf/d (30 mmcf/d net to Nexen). We have a 50% non-operated interest.
At Aspen, we are completing a sidetrack well to exploit a number of deeper sands. We expect this well to come on stream in the third quarter. We have a 100% operated working interest at Aspen.
We are currently drilling our Vicksburg exploration well located on De Soto Canyon Block 353 in the Eastern Gulf. The pre-drill unrisked resource estimate is between 200 and 500 million boe. We expect to have drilling results late in the third quarter. We have a 25% non-operated working interest.
At Knotty Head located on Green Canyon Block 512, we are expecting to drill our next appraisal well in the first half of 2008. Our current estimate of resource for the field is between 200 and 500 million boe. We have a 25% operated interest in the field.
At Longhorn (previously named Ringo) located on Mississippi Canyon Block 546, we have an appraisal well planned later this year and at Alaminos Canyon Block 856 (Great White West), we are continuing to evaluate development options. We have non-operated working interests of 25% and 30% in these projects, respectively.
Coalbed Methane (CBM) Development Continues
Our Mannville CBM project in the Fort Assiniboine area of Alberta is currently producing approximately 24 mmcf/d. We expect this to double by year-end and continue to grow as we develop additional sections of land in the Corbett, Thunder and Doris fields using multiple-leg horizontal wells.
"We remain confident that we can achieve CBM production volumes of at least 150 mmcf/d by 2011," said Fischer.
Offshore West Africa
The Usan field development, located in Nigeria on offshore Block OPL-222, continues to progress toward project sanction. The project will have the ability to process an average of 180,000 bbls/d of oil during the initial production plateau period through a new FPSO with a two million barrel storage capacity. We expect the Usan development to be formally sanctioned this year, at which time the major deep-water facilities and drilling contracts will be awarded. We have a 20% interest in exploration and development on this block.
Exploration
Over the next 12 months or so, we expect to drill at least 18 exploration wells with the majority in the Gulf of Mexico and the UK North Sea. During the quarter, we were also awarded an additional two licences in the Norwegian North Sea.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.025 per common share payable October 1, 2007, to shareholders of record on September 10, 2007. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the North Sea, deep-water Gulf of Mexico, the Athabasca oil sands of Alberta, the Middle East and offshore West Africa. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity and environmental protection.
Conference Call
Charlie Fischer, President and CEO, and Marvin Romanow, Executive
Vice President and CFO, will host a conference call to discuss our financial
and operating results and expectations for the future.
Date: July 12, 2007
Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)
To listen to the conference call, please call one of the following:
416-641-6126 (Toronto)
866-542-4236 (North American toll-free)
800-8989-6323 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 3227304 followed by the pound sign. A live and on demand webcast of the conference call will be available at www.nexeninc.com/investors.
Forward-Looking Statements
Certain statements in this report constitute "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. Such statements are generally identifiable by the terminology used such as "intend", "plan", "expect", "estimate", "budget", "outlook" or other similar words, and include statements relating to expected full year production, cash flow and capital expenditures as well as future production associated with our coalbed methane, Long Lake, Syncrude, North Sea, Gulf of Mexico, West Africa projects and other projects.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce and transport crude oil and natural gas to markets; the results of exploration and development drilling and related activities; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions that increase taxes or royalties, change environmental and other laws and regulations; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. 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. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future cost recovery oil revenues from our Yemen operations, future capital expenditures and their allocation to exploration and development activities, future asset dispositions, future sources of funding for our capital program, future debt levels, possible commerciality, development plans or capacity expansions, future ability to execute dispositions of assets or businesses, future cash flows and their uses, future drilling of new wells, ultimate recoverability of reserves, expected finding and development costs, expected operating costs, future demand for chemicals products, future expenditures and future allowances relating to environmental matters and dates by which certain areas will be developed or will come on stream, and changes in any of the foregoing are forward-looking statements.
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. Readers should also refer to Items 1A and 7A in our 2006 Annual Report on Form 10-K for further discussion of the risk factors.
Cautionary Note to US Investors - The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to discuss only proved reserves that are supported by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. In this press release, we may refer to "recoverable reserves", "probable reserves" and "recoverable resources" which are inherently more uncertain than proved reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Report on Form 10-K available from us or the SEC for further reserve disclosure.
In addition, under SEC regulations, the Syncrude oil sands operations are considered mining activities rather than oil and gas activities. Production, reserves and related measures in this release include results from the Company's share of Syncrude.
Cautionary Note to Canadian Investors - Nexen is required to disclose oil and gas activities under National Instrument 51-101- Standards of Disclosure for Oil and Gas Activities (NI 51-101). However, the Canadian securities regulatory authorities (CSA) have granted us exemptions from certain provisions of NI 51-101 to permit US style disclosure. These exemptions were sought because we are a US Securities and Exchange Commission (SEC) Registrant and our securities regulatory disclosures, including Form 10-K and other related forms, must comply with SEC requirements. Our disclosures may differ from those Canadian companies who have not received similar exemptions under NI 51-101.
Please read the "Special Note to Canadian Investors" in Item 7A in our 2006 Annual Report on Form 10-K, for a summary of the exemption granted by the CSA and the major differences between SEC requirements and NI 51-101. The summary is not intended to be all-inclusive or to convey specific advice. Reserve estimation is highly technical and requires professional collaboration and judgment. The differences between SEC requirements and NI 51-101 may be material.
Our probable reserves disclosure applies the Society of Petroleum Engineers/World Petroleum Council (SPE/WPC) definition for probable reserves. The Canadian Oil and Gas Evaluation Handbook states there should not be a significant difference in estimated probable reserve quantities using the SPE/WPC definition versus NI 51-101.
In this press release, we refer to oil and gas in common units called barrel of oil equivalent (boe). A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6mcf:1bbl). This conversion may be misleading, particularly if used in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head.
Nexen Inc.
Financial Highlights
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Sales 1,399 1,039 2,539 2,019
Cash Flow from Operations 913 729 1,511 1,402
Per Common Share ($/share) (1) 1.73 1.39 2.87 2.68
Net Income 368 408 489 325
Per Common Share ($/share) (1) 0.70 0.78 0.93 0.62
Capital Investment, including
Acquisitions (2) 819 876 1,630 1,629
Net Debt (3) 4,755 3,930 4,755 3,930
Common Shares Outstanding
(millions of shares) (1) 527.1 524.3 527.1 524.3
-----------------------------------------
(1) Restated to reflect a two-for-one stock split in the second quarter of
2007.
(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 Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Oil & Gas and Syncrude
Yemen (2) 182 244 340 465
Canada 51 78 95 132
United States 113 132 246 274
United Kingdom 562 189 853 302
Other Countries 25 29 32 50
Marketing 70 69 71 244
Syncrude 60 65 127 90
-----------------------------------------
1,063 806 1,764 1,557
Chemicals 18 24 36 46
-----------------------------------------
1,081 830 1,800 1,603
Interest and Other Corporate Items (82) (46) (187) (104)
Income Taxes(3) (86) (55) (102) (97)
-----------------------------------------
Cash Flow from Operations (1) 913 729 1,511 1,402
-----------------------------------------
-----------------------------------------
(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 and the ability of our business segments to
generate the cash flow necessary to fund future growth through capital
investment and repay debt. Cash flow from operations may not be
comparable with the calculation of similar measures for other companies.
Reconciliation of Cash Flow Three Months Six Months
from Operations Ended June 30 Ended June 30
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash Flow from Operating Activities 582 374 1,030 1,108
Changes in Non-Cash Working Capital 304 377 272 304
Other 34 (4) 223 27
Amortization of Premium for Crude
Oil Put Options (7) (18) (14) (37)
-----------------------------------------
Cash Flow from Operations 913 729 1,511 1,402
-----------------------------------------
-----------------------------------------
Weighted-average Number of Common
Shares Outstanding (millions of
shares) 527.0 524.2 526.5 523.8
-----------------------------------------
Cash Flow from Operations Per
Common Share ($/share) 1.73 1.39 2.87 2.68
-----------------------------------------
-----------------------------------------
(2) After in-country cash taxes of $65 million for the three months ended
June 30, 2007 (2006 - $81 million) and $109 million for the six months
ended June 30, 2007 (2006 - $148 million).
(3) Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 73.3 95.2 75.2 98.8
Canada 17.2 20.6 17.5 21.4
United States 16.0 17.8 18.8 18.5
United Kingdom 85.6 17.2 70.7 16.5
Other Countries 6.2 6.6 6.0 6.2
Syncrude (2) 19.0 17.4 20.2 16.1
-----------------------------------------
217.3 174.8 208.4 177.5
-----------------------------------------
Natural Gas (mmcf/d)
Canada 116 104 117 105
United States 86 107 93 114
United Kingdom 14 32 14 27
-----------------------------------------
216 243 224 246
-----------------------------------------
Total Production (mboe/d) 253 215 246 219
-----------------------------------------
-----------------------------------------
Production Volumes (after royalties)
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 41.6 52.3 43.3 53.0
Canada 13.4 16.2 13.8 17.0
United States 14.2 15.6 16.8 16.3
United Kingdom 85.6 17.2 70.7 16.5
Other Countries 5.7 6.0 5.5 5.7
Syncrude (2) 16.4 15.7 17.6 14.5
-----------------------------------------
176.9 123.0 167.7 123.0
-----------------------------------------
Natural Gas (mmcf/d)
Canada 97 88 96 89
United States 74 91 80 97
United Kingdom 14 32 14 27
-----------------------------------------
185 211 190 213
-----------------------------------------
Total Production (mboe/d) 208 158 199 159
-----------------------------------------
-----------------------------------------
Notes:
(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) Considered a mining operation for US reporting purposes.
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Total
(all dollar Quarters - 2007 Quarters - 2006 Year
amounts in Cdn$ -----------------------------------------------------
unless noted) 1st 2nd 1st 2nd 3rd 4th 2006
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 58.16 65.03 63.48 70.70 70.48 60.21 66.22
Nexen Average - Oil
(Cdn$/bbl) 61.69 72.27 63.11 72.90 73.06 60.89 67.50
NYMEX Natural Gas
(US$/mmbtu) 7.18 7.66 7.87 6.67 6.14 7.26 6.99
Nexen Average -
Gas (Cdn$/mcf) 7.58 7.52 8.71 6.68 6.39 6.84 7.18
----------------------------------------------------------------------------
NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 17.8 17.2 21.9 20.1 19.0 18.3 19.8
Price Received ($/bbl) 41.71 41.89 30.00 51.67 52.95 37.61 42.79
Royalties & Other 9.16 9.52 6.25 11.38 12.55 8.43 9.58
Operating Costs 13.65 15.14 11.47 11.66 12.61 12.98 12.15
----------------------------------------------------------------------------
Netback 18.90 17.23 12.28 28.63 27.79 16.20 21.06
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 118 116 106 104 106 118 108
Price Received ($/mcf) 7.16 7.06 7.65 6.21 5.78 6.37 6.49
Royalties & Other 1.26 1.09 1.17 0.89 0.90 0.98 0.97
Operating Costs 1.59 1.81 1.27 1.33 1.33 1.64 1.38
----------------------------------------------------------------------------
Netback 4.31 4.16 5.21 3.99 3.55 3.75 4.14
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 77.5 72.7 102.6 94.5 88.8 85.1 92.7
Price Received ($/bbl) 63.02 77.34 68.32 76.86 76.08 64.90 71.57
Royalties & Other 28.17 33.84 32.73 34.60 34.80 26.76 32.32
Operating Costs 6.07 6.29 3.88 4.39 4.53 5.11 4.45
In-country Taxes 6.38 9.89 7.20 9.46 9.29 7.94 8.45
----------------------------------------------------------------------------
Netback 22.40 27.32 24.51 28.41 27.46 25.09 26.35
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 21.4 19.0 14.8 17.4 20.5 21.9 18.7
Price Received ($/bbl) 70.03 77.12 69.95 79.50 77.53 63.37 72.32
Royalties & Other 8.26 10.33 6.68 7.95 8.54 4.79 6.93
Operating Costs 24.40 29.91 40.12 27.84 21.69 24.42 27.53
----------------------------------------------------------------------------
Netback 37.37 36.88 23.15 43.71 47.30 34.16 37.86
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 21.6 16.0 19.3 17.8 16.7 14.6 17.0
Price Received ($/bbl) 58.49 68.18 63.73 70.23 70.23 58.09 65.80
Natural Gas:
Sales (mmcf/d) 101 86 120 107 105 111 111
Price Received ($/mcf) 8.58 8.85 9.06 7.51 7.18 7.56 7.86
Total Sales Volume
(mboe/d) 38.4 30.4 39.3 35.6 34.1 33.0 35.5
Price Received ($/boe) 55.44 61.04 58.97 57.60 56.35 50.97 56.12
Royalties & Other 6.78 7.71 7.96 7.62 7.42 7.06 7.53
Operating Costs 8.11 9.46 8.47 7.00 8.42 8.78 8.17
----------------------------------------------------------------------------
Netback 40.55 43.87 42.54 42.98 40.51 35.13 40.42
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 58.8 87.2 17.6 17.9 13.8 16.2 16.3
Price Received ($/bbl) 64.33 74.07 69.02 73.24 77.73 65.67 71.19
Natural Gas:
Sales (mmcf/d) 13 13 24 29 10 15 19
Price Received ($/mcf) 3.87 3.32 11.82 5.52 5.57 5.52 7.43
Total Sales Volume
(mboe/d) 60.8 89.3 21.5 22.8 15.4 18.6 19.6
Price Received ($/boe) 62.92 72.75 69.37 64.59 73.13 61.38 66.81
Royalties & Other - - - - - - -
Operating Costs 9.60 6.59 11.24 9.59 15.12 10.18 11.28
----------------------------------------------------------------------------
Netback 53.32 66.16 58.13 55.00 58.01 51.20 55.53
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 5.8 6.2 5.8 6.6 6.7 6.0 6.3
Price Received ($/bbl) 59.81 68.04 58.81 69.63 74.05 60.22 66.09
Royalties & Other 4.80 5.62 4.71 5.92 6.33 4.89 5.51
Operating Costs 2.97 3.39 2.27 2.74 2.55 3.93 2.87
----------------------------------------------------------------------------
Netback 52.04 59.03 51.83 60.97 65.17 51.40 57.71
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales
(mboe/d) 241.5 254.1 223.5 214.5 202.1 202.6 210.6
Price Received ($/boe) 59.13 68.48 61.11 66.78 66.82 56.95 62.92
Royalties & Other 12.26 12.65 18.04 18.95 19.25 14.38 17.68
Operating Costs 9.67 9.41 8.78 8.21 8.72 9.40 8.77
In-country Taxes 2.05 2.83 3.31 4.17 4.08 3.33 3.72
----------------------------------------------------------------------------
Netback 35.15 43.59 30.98 35.45 34.77 29.84 32.75
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
Nexen Inc.
Unaudited Consolidated Statement of Income
For the Three and Six Months Ended June 30
Cdn$ millions, except per share amounts
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,399 1,039 2,539 2,019
Marketing and Other (Note 13) 299 376 547 802
-----------------------------------------
1,698 1,415 3,086 2,821
-----------------------------------------
Expenses
Operating 289 223 579 473
Depreciation, Depletion,
Amortization and Impairment 360 260 694 526
Transportation and Other 210 203 456 463
General and Administrative 38 108 240 328
Exploration 105 46 154 149
Interest (Note 6) 46 11 94 20
-----------------------------------------
1,048 851 2,217 1,959
-----------------------------------------
Income before Income Taxes 650 564 869 862
-----------------------------------------
Provision for Income Taxes
Current 151 136 211 245
Future 126 14 161 283
-----------------------------------------
277 150 372 528
-----------------------------------------
Net Income before Non-Controlling
Interests 373 414 497 334
Less: Net Income Attributable to
Non-Controlling Interests (5) (6) (8) (9)
-----------------------------------------
Net Income 368 408 489 325
-----------------------------------------
-----------------------------------------
Earnings Per Common Share ($/share)
Basic (Note 11) 0.70 0.78 0.93 0.62
-----------------------------------------
-----------------------------------------
Diluted (Note 11) 0.68 0.76 0.91 0.61
-----------------------------------------
-----------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Balance Sheet
Cdn$ millions, except share amounts
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 158 101
Restricted Cash and Margin Deposits 96 197
Accounts Receivable (Note 2) 2,861 2,951
Inventories and Supplies (Note 3) 857 786
Future Income Tax Assets 277 479
Other 51 67
----------------------
Total Current Assets 4,300 4,581
----------------------
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $6,502
(December 31, 2006 - $6,399) 12,147 11,739
Future Income Tax Assets 78 141
Deferred Charges and Other Assets (Note 4) 321 318
Goodwill 348 377
----------------------
Total Assets 17,194 17,156
----------------------
----------------------
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Borrowings (Note 6) 61 158
Accounts Payable and Accrued Liabilities 3,665 3,879
Accrued Interest Payable 65 55
Dividends Payable 13 13
----------------------
Total Current Liabilities 3,804 4,105
----------------------
Long-Term Debt (Note 6) 4,852 4,673
Future Income Tax Liabilities 2,274 2,468
Asset Retirement Obligations (Note 7) 690 683
Deferred Credits and Other Liabilities (Note 8) 421 516
Non-Controlling Interests 73 75
Shareholders' Equity (Note 10)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 527,149,918 shares
2006 - 525,026,412 shares 893 821
Contributed Surplus 5 4
Retained Earnings 4,435 3,972
Accumulated Other Comprehensive Income (Note 1) (253) (161)
----------------------
Total Shareholders' Equity 5,080 4,636
----------------------
Commitments, Contingencies and Guarantees (Note 14)
----------------------
Total Liabilities and Shareholders' Equity 17,194 17,156
----------------------
----------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three and Six Months Ended June 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating Activities
Net Income 368 408 489 325
Charges and Credits to Income not
Involving Cash (Note 12) 447 293 882 965
Exploration Expense 105 46 154 149
Changes in Non-Cash Working Capital
(Note 12) (304) (377) (272) (304)
Other (34) 4 (223) (27)
-----------------------------------------
582 374 1,030 1,108
Financing Activities
Proceeds from Long-Term Notes 1,660 - 1,660 -
Proceeds from (Repayment of) Term
Credit Facilities, Net (1,321) 417 (955) 413
Proceeds from Term Credit
Facilities of Canexus 15 - 33 -
Proceeds from (Repayment of)
Short-Term Borrowings, Net (44) 50 (92) 85
Dividends on Common Shares (Note 10) (13) (13) (26) (26)
Issue of Common Shares and Exercise
of Stock Options 11 24 40 37
Other (28) (7) (35) (14)
-----------------------------------------
280 471 625 495
Investing Activities
Capital Expenditures
Exploration and Development (747) (767) (1,537) (1,486)
Proved Property Acquisitions (45) - (46) (3)
Chemicals, Corporate and Other (27) (52) (47) (62)
Business Acquisitions, Net of Cash
Acquired - (57) - (78)
Proceeds on Disposition of Assets - 25 - 25
Changes in Restricted Cash and
Margin Deposits 66 66 82 12
Changes in Non-Cash Working Capital
(Note 12) 16 36 44 59
Other (10) (11) (14) (4)
-----------------------------------------
(747) (760) (1,518) (1,537)
Effect of Exchange Rate Changes on
Cash and Cash Equivalents (67) (29) (80) (28)
-----------------------------------------
Increase in Cash and Cash
Equivalents 48 56 57 38
Cash and Cash Equivalents -
Beginning of Period 110 30 101 48
-----------------------------------------
Cash and Cash Equivalents - End of
Period 158 86 158 86
-----------------------------------------
-----------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Shareholders' Equity
For the Three and Six Months Ended June 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 866 763 821 732
Issue of Common Shares 4 21 25 26
Proceeds from Options Exercised for
Shares 7 3 15 11
Accrued Liability Relating to
Options Exercised for Shares 16 12 32 30
-----------------------------------------
Balance at End of Period 893 799 893 799
-----------------------------------------
-----------------------------------------
Contributed Surplus
Balance at Beginning of Period 4 2 4 2
Stock-Based Compensation Expense 1 1 1 1
-----------------------------------------
Balance at End of Period 5 3 5 3
-----------------------------------------
-----------------------------------------
Retained Earnings
Balance at Beginning of Period 4,080 3,327 3,972 3,423
Net Income 368 408 489 325
Dividends on Common Shares (13) (13) (26) (26)
-----------------------------------------
Balance at End of Period 4,435 3,722 4,435 3,722
-----------------------------------------
-----------------------------------------
Accumulated Other Comprehensive
Income
Balance at Beginning of Period (167) (167) (161) -
Opening Cumulative Foreign Currency
Translation Adjustment (Note 1) - - - (161)
Opening Derivatives Designated as
Cash Flow Hedges (Note 1) - - 61 -
Other Comprehensive Income (86) (63) (153) (69)
-----------------------------------------
Balance at End of Period (253) (230) (253) (230)
-----------------------------------------
-----------------------------------------
Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three and Six Months Ended June 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net Income 368 408 489 325
Other Comprehensive Income, Net of
Income Taxes:
Foreign Currency Translation
Adjustment:
Net Losses on Investment in
Self-Sustaining Foreign
Operations (437) (220) (495) (218)
Net Gains on Hedges of
Self-Sustaining Foreign
Operations (1) 353 154 403 147
Realized Translation Adjustments
Recognized in Net Income (2) (2) 3 - 2
Cash Flow Hedges:
Realized Mark to Market Gains
Recognized in Net Income - - (61) -
-----------------------------------------
Other Comprehensive Income (86) (63) (153) (69)
-----------------------------------------
Comprehensive Income 282 345 336 256
-----------------------------------------
-----------------------------------------
(1) Net of income taxes for the three months ended June 30 of $57 million
(2006 - $19 million) and for the six months ended June 30 of $66 million
(2006 - $18 million).
(2) Net of income taxes for the three months ended June 30 of $1 million
(2006 - nil) and six months ended June 30 of $nil (2006 - $nil).
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Consolidated Financial Statements
Cdn$ millions except as noted
1. ACCOUNTING POLICIES
Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States (US) GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 16. In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.'s (Nexen, we or our) financial position at June 30, 2007 and the results of our operations and our cash flows for the three and six months ended June 30, 2007 and 2006.
We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates, including those related to accruals, litigation, environmental and asset retirement obligations, income taxes, derivative contract assets and liabilities and determination of proved reserves, on an ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three and six months ended June 30, 2007 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2007.
These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2006 Annual Report on Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2006 Annual Report on Form 10-K.
Change in Accounting Policies
On January 1, 2007, we adopted the following new accounting standards issued by the Canadian Accounting Standards Board (AcSB): Financial Instruments-Recognition and Measurement (Section 3855), Hedges (Section 3865) and Comprehensive Income (Section 1530).
Financial Instruments-Recognition and Measurement
Section 3855 requires all financial assets and liabilities to be carried at fair value in the Unaudited Consolidated Balance Sheet with the exception of loans and receivables, investments that are intended to be held to maturity and non-trading financial liabilities which are to be carried at cost or amortized cost.
Realized and unrealized gains and losses on financial assets and liabilities carried at fair value are recognized in the Unaudited Consolidated Statement of Income in the periods such gains and losses arise. Transaction costs related to these financial assets and liabilities are included in the Unaudited Consolidated Statement of Income when incurred. Unrealized gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in the Unaudited Consolidated Statement of Income when these assets or liabilities settle.
We hold financial instruments that were carried at fair value prior to the adoption of Section 3855 as described in Note 9. The valuation methods we use to determine the fair value of these financial instruments remain unchanged. Financial instruments we carry at cost or amortized cost include our accounts receivable, accounts payable, short-term and long-term debt. Upon adopting Section 3855 with respect to the amortized cost using the effective interest rate method of our long-term debt, we have reclassed deferred financing costs previously included in deferred charges and other assets as unamortized debt issue costs which reduce the carrying value of our long-term debt.
Hedges
Section 3865 prescribes new standards for hedge accounting.
For cash flow hedges, changes in the fair value of a financial instrument designated as a cash flow hedge are recognized in the Unaudited Consolidated Statement of Income in the same period as the hedged item. Any fair value change in the financial instrument before that period is recognized on the Unaudited Consolidated Balance Sheet. The effective portion of this fair value change is recognized in other comprehensive income with any ineffectiveness recognized in the Unaudited Consolidated Statement of Income during the period of change.
For fair value hedges, both the financial instrument designated as a fair value hedge and the underlying commitment are recognized on the Unaudited Consolidated Balance Sheet at fair value. Changes in the fair value of both are reflected in the Unaudited Consolidated Statement of Income.
Adoption of these new standards for hedge accounting required us to record unrealized mark to market gains on cash flow hedges that were previously not included on our Unaudited Consolidated Balance Sheet at December 31, 2006 as an adjustment to the opening balance of accumulated other comprehensive income (see Note 9).
Comprehensive Income
Section 1530 provides for a new Statement of Comprehensive Income and establishes accumulated other comprehensive income as a separate component of shareholders' equity. The Unaudited Consolidated Statement of Comprehensive Income reflects changes in accumulated other comprehensive income and includes the effective portion of changes in the fair value of financial instruments designated as cash flow hedges, as well as changes in foreign currency translation amounts arising in respect of self-sustaining foreign operations together with the impact of any related hedges. Amounts included in accumulated other comprehensive income are reclassified to the Unaudited Consolidated Statement of Income when realized. On adoption of Section 1530, cumulative foreign currency translation adjustments relating to our self-sustaining foreign operations were reclassed to accumulated other comprehensive income and comparative amounts have been restated.
We adopted these standards prospectively. Comparative amounts for prior periods have not been restated with the exception of amounts related to cumulative foreign currency translation adjustments. Adoption of these standards as at January 1, 2007 had the following impact on our Unaudited Consolidated Balance Sheet:
January 1, 2007
Increase/(Decrease)
----------------------------------------------------------------------------
To Include Unrealized Mark to Market Gains on Cash
Flow Hedges at December 31, 2006:
Accounts Receivable 25
Accounts Payable and Accrued Liabilities (65)
Future Income Tax Liabilities 29
Accumulated Other Comprehensive Income 61
To Include Cumulative Foreign Currency Translation
in Accumulated Other Comprehensive Income:
Cumulative Foreign Currency Translation Adjustment 161
Accumulated Other Comprehensive Income (161)
To Include Unamortized Debt Issue Costs with
Long-Term Debt:
Deferred Charges and Other Assets (59)
Long-Term Debt (59)
-------------------
2. ACCOUNTS RECEIVABLE
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Trade
Marketing 2,006 2,226
Oil and Gas 705 600
Chemicals and Other 63 58
-------------------------
2,774 2,884
Non-Trade 99 80
-------------------------
2,873 2,964
Allowance for Doubtful Receivables (12) (13)
-------------------------
Total 2,861 2,951
-------------------------
-------------------------
3. INVENTORIES AND SUPPLIES
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Finished Products
Marketing 722 609
Oil and Gas 2 21
Chemicals and Other 12 14
-------------------------
736 644
Work in Process 6 5
Field Supplies 115 137
-------------------------
Total 857 786
-------------------------
-------------------------
4. DEFERRED CHARGES AND OTHER ASSETS
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 9) 208 153
Deferred Financing Costs (Note 1) - 59
Asset Retirement Remediation Fund 14 13
Crude Oil Put Options (Note 9) 23 19
Other 76 74
-------------------------
Total 321 318
-------------------------
-------------------------
5. SUSPENDED WELL COSTS
The following table shows the changes in capitalized exploratory well costs during the six month period ended June 30, 2007 and the year ended December 31, 2006, and does not include amounts that were initially capitalized and subsequently expensed in the same period.
Six Months Ended Year Ended
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 226 252
Additions to Capitalized Exploratory Well
Costs Pending the Determination of
Proved Reserves 77 129
Capitalized Exploratory Well Costs
Charged to Expense (22) (70)
Transfers to Wells, Facilities and
Equipment Based on Determination of
Proved Reserves (8) (84)
Effects of Foreign Exchange (18) (1)
----------------------------------
Balance at End of Period 255 226
----------------------------------
----------------------------------
The following table provides an aging of capitalized exploratory well costs
based on the date drilling was completed and shows the number of projects
for which exploratory well costs have been capitalized for a period greater
than one year after the completion of drilling.
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 104 179
Capitalized for a Period of Greater than One Year 151 47
-------------------------
Balance at End of Period 255 226
-------------------------
-------------------------
Number of Projects that have Exploratory Well
Costs Capitalized for a Period
Greater than One Year 6 4
-------------------------
-------------------------
As at June 30, 2007, we have exploratory costs that have been capitalized for more than one year relating to our interest in two exploratory blocks in the Gulf of Mexico ($98 million), our interest in an exploratory block offshore Nigeria ($19 million), our coalbed methane exploratory activities in Canada ($17 million), an exploratory well on Block 51 in Yemen ($11 million) and an exploratory block in the North Sea ($6 million). We have capitalized costs related to successful wells drilled in Nigeria, Gulf of Mexico, North Sea, and at Block 51 in Yemen. In Canada, we have capitalized exploratory costs relating to our coalbed methane projects. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or to assess commercial viability.
6. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Term Credit Facilities (a) - 1,078
Canexus LP Term Credit Facilities (US$178 million) 189 174
Medium-Term Notes, due 2007 (1) 150 150
Medium-Term Notes, due 2008 125 125
Notes, due 2013 (US$500 million) 532 583
Notes, due 2015 (US$250 million) 266 291
Notes, due 2017 (US$250 million) (b) 266 -
Notes, due 2028 (US$200 million) 213 233
Notes, due 2032 (US$500 million) 532 583
Notes, due 2035 (US$790 million) 840 920
Notes, due 2037 (US$1,250 million) (c) 1,329 -
Subordinated Debentures, due 2043 (US$460 million) 489 536
-------------------------
4,931 4,673
Unamortized Debt Issue Costs (Note 1) (79) -
-------------------------
Total Long-Term Debt 4,852 4,673
-------------------------
-------------------------
(1) Amounts due July 2007 are not included in current liabilities as we
expect to refinance this amount with our term credit facilities.
(a) Term credit facilities
We have committed, unsecured term credit facilities of $3.3 billion, which are available to 2011. The lenders have the option to extend the term annually. At June 30, 2007 we had not drawn on these facilities (December 31, 2006 - $1,078 million). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable monthly at floating rates. The weighted-average interest rate on our term credit facilities was 5.9% for the three months ended June 30, 2007 (2006 - 5.7%) and 5.9% for the six months ended June 30, 2007 (2006 - 5.5%). At June 30, 2007, $397 million of these facilities were utilized to support outstanding letters of credit (December 31, 2006 - $294 million).
(b) Notes, due 2017
In May 2007, we issued US$250 million of 10 year notes. Interest is payable semi-annually at a rate of 5.65% and the principal is to be repaid in May 2017. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.2%. The proceeds were used to repay the outstanding term credit facilities.
(c) Notes, due 2037
In May 2007, we issued US$1,250 million of 30 year notes. Interest is payable semi-annually at a rate of 6.40% and the principal is to be repaid in May 2037. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.35%. The proceeds were used to repay the outstanding term credit facilities.
(d) Interest expense
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Long-Term Debt 83 65 164 127
Other 4 6 9 10
-------------------------------
87 71 173 137
Less: Capitalized (41) (60) (79) (117)
-------------------------------
Total 46 11 94 20
-------------------------------
-------------------------------
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.
(e) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $631 million, of which $61 million (US$57 million) was drawn at June 30, 2007 (December 31, 2006 - $158 million). We have also utilized $130 million of these facilities to support outstanding letters of credit at June 30, 2007 (December 31, 2006 - $252 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 5.8% for the three months ended June 30, 2007 (2006 - 5.4%) and 5.8% for the six months ended June 30, 2007 (2006 - 5.3%).
7. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment for the six months ended June 30, 2007 and the year ended December 31, 2006, are as follows:
Six Months Ended Year Ended
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 704 611
Obligations Assumed with Development
Activities 36 75
Obligations Discharged with Disposed
Properties - (1)
Expenditures Made on Asset Retirements (12) (44)
Accretion 22 37
Revisions to Estimates (3) (10)
Effects of Foreign Exchange (36) 36
----------------------------------
Balance at End of Period (1,2) 711 704
----------------------------------
----------------------------------
(1) Obligations due within 12 months of $21 million (December 31, 2006 - $21
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $665
million (December 31, 2006 - $658 million) and obligations relating to our
chemicals business amount to $46 million (December 31, 2006 - $46 million).
Our total estimated undiscounted asset retirement obligations amount to $1,783 million (December 31, 2006 - $1,770 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.7%. Approximately $94 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations.
We own interests in assets for which the fair value of the asset retirement obligations cannot be reasonably determined because the assets currently have an indeterminate life and we cannot determine when remediation activities would take place. These assets include our interest in Syncrude's upgrader and sulphur pile. The estimated future recoverable reserves at Syncrude are significant and given the long life of this asset, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant can continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the lives of the assets are determinable.
8. DEFERRED CREDITS AND OTHER LIABILITIES
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 9) 111 199
Deferred Transportation Revenue 87 89
Fixed-Price Natural Gas Contracts (Note 9) 62 74
Capital Lease Obligations 50 48
Defined Benefit Pension Obligations 50 48
Stock-Based Compensation Liability 13 6
Other 48 52
-------------------------
Total 421 516
-------------------------
-------------------------
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
We use derivatives in our marketing group for trading purposes and we also use derivatives to manage commodity price risk for non-trading purposes. Our derivative instruments are carried at fair value on the Unaudited Consolidated Balance Sheet. Our other financial instruments are carried at cost or amortized cost.
(a) Carrying value and estimated fair value of financial instruments
The carrying value, fair value, and unrecognized gains or losses on our outstanding derivatives and other financial liabilities are:
June 30, 2007
----------------------------------------------------------------------------
Carrying Fair Unrecognized
Value Value Gain/(Loss)
-------------------------------
Derivatives
Commodity Price Risk
Non-Trading Activities
Crude Oil Put Options 23 23 -
Fixed-Price Natural Gas Contracts (85) (85) -
Natural Gas Swaps (5) (5) -
Trading Activities
Crude Oil and Natural Gas 129 129 -
Future Sale of Gas Inventory - - -
Foreign Currency Exchange Rate Risk
Trading Activities 2 2 -
-------------------------------
Total Derivatives 64 64 -
-------------------------------
-------------------------------
Other Financial Liabilities
Long-Term Debt (4,852) (4,819) 33
-------------------------------
-------------------------------
December 31, 2006
----------------------------------------------------------------------------
Carrying Fair Unrecognized
Value Value Gain/(Loss)
-------------------------------
Derivatives
Commodity Price Risk
Non-Trading Activities
Crude Oil Put Options 19 19 -
Fixed-Price Natural Gas Contracts (96) (96) -
Natural Gas Swaps (8) (8) -
Trading Activities
Crude Oil and Natural Gas 372 372 -
Future Sale of Gas Inventory - 25 25
Foreign Currency Exchange Rate Risk
Trading Activities (12) (12) -
-------------------------------
Total Derivatives 275 300 25
-------------------------------
-------------------------------
Other Financial Liabilities
Long-Term Debt (4,673) (4,728) (55)
-------------------------------
-------------------------------
The estimated fair value of all derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers or dealers. Other financial assets used in the normal course of business include cash and cash equivalents, restricted cash and margin deposits and accounts receivable. Other financial liabilities include accounts payable, accrued interest payable, short-term borrowings and long-term debt. Fair value of long-term debt is estimated based on third-party brokers and quoted market prices.
(b) Commodity price risk management
Non-Trading Activities
We generally sell our crude oil and natural gas under short-term market based contracts.
Crude oil put options
In 2006, we purchased WTI crude oil put options to provide a base level of price protection without limiting our upside to higher prices. These options establish an annual average WTI floor price of US$50/bbl in 2007 on 105,000 bbls/d at a cost of $26 million. The crude oil put options are stated at fair value and are included in accounts receivable as they settle within 12 months. Any change in fair value is included in marketing and other on the Unaudited Consolidated Statement of Income.
During the quarter, we purchased put options on 36 million barrels or about 100,000 bbls/d of our 2008 crude oil production. These options establish a Dated Brent floor price of US$50/bbl on these volumes and are settled annually. The put options were purchased for $24 million and are carried at fair value. Any change in fair value is included in marketing and other income on the Unaudited Consolidated Statement of Income.
Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
WTI Crude Oil Put Options 105,000 2007 50 -
Dated Brent Crude Oil Put
Options 100,000 2008 50 23
---------------
23
---------------
---------------
Fixed-price natural gas contracts and natural gas swaps
In July and August 2005, we sold certain Canadian oil and gas properties and retained fixed-price natural gas sales contracts that were previously associated with those properties. Since these contracts are no longer used in the normal course of our oil and gas operations, they have been included in the Unaudited Consolidated Balance Sheet at fair value. Amounts settling within 12 months are included in accounts payable and amounts settling greater than 12 months are included in deferred credits and other liabilities. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income.
Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed-Price Natural Gas
Contracts 15,514 2007 - 2008 2.46 (23)
15,514 2008 - 2010 2.56 - 2.77 (62)
---------------
(85)
---------------
---------------
Following the sale of the Canadian oil and gas properties, we entered into natural gas swaps to hedge our fixed price exposure with floating natural gas prices. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income. Amounts settling within 12 months are included in accounts receivable and amounts settling greater than 12 months are included in deferred charges and other assets.
Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Natural Gas Swaps 15,514 2007 - 2008 7.60 (5)
15,514 2008 - 2010 7.60 -
---------------
(5)
---------------
---------------
Trading Activities
Crude oil and natural gas
We enter into physical purchase and sales contracts as well as financial commodity contracts to enhance our price realizations and lock in our margins. The physical and financial commodity contracts (derivative contracts) are stated at fair value. The $129 million fair value of the derivative contracts at June 30, 2007 is included in the Unaudited Consolidated Balance Sheet and any change is included in marketing and other in the Unaudited Consolidated Statement of Income.
Future sale of gas inventory
In an attempt to mitigate the exposure to fluctuations in cash flow from changes in the price of natural gas we have certain NYMEX futures contracts and swaps in place, which effectively lock in our margins on the future sale of our natural gas inventory in storage. From time to time, we have designated, in writing, some of these derivative contracts as cash flow hedges of the future sale of our storage inventory.
With the adoption of Section 3865 Hedges as described in Note 1, the effective portion of gains and losses relating to cash flow hedges are now included in other comprehensive income until the gains or losses are realized in net income. Prior to the adoption of Section 3865, gains and losses related to derivatives classified as cash flow hedges were unrecognized.
At December 31, 2006, we held NYMEX natural gas futures contracts and swaps that were designated as cash flow hedges on the future sale of natural gas inventory. On adoption of Section 3865, the fair value of $25 million related to these cash flow hedges was recognized in accounts receivable on January 1, 2007. The fair value gain of $16 million, net of income taxes, was included with the opening balance of accumulated other comprehensive income (AOCI). During the first quarter of 2007, the inventory was sold and as a result, gains on these cash flow hedges were recognized in marketing and other on the Unaudited Consolidated Statement of Income.
In late 2006, we de-designated certain futures contracts that had been designated as cash flow hedges of future sales of our natural gas in storage. These contracts were de-designated since it became uncertain that the future sales of natural gas would occur within the designated time frame. As it was reasonably possible that the future sales could have taken place as designated at the inception of the hedging relationship, gains of $65 million on the futures contracts were deferred in accounts payable at December 31, 2006. The adoption of Section 3865 required that the deferred gains ($45 million, net of income taxes) be reclassified to AOCI on January 1, 2007. The gains were recognized in marketing and other on the Unaudited Consolidated Statement of Income during the first quarter of 2007.
At June 30, 2007, there were no cash flow hedges in place.
(c) Foreign currency exchange rate risk management
Trading Activities
Our sales and purchases of crude oil and natural gas are generally transacted in or referenced to the US dollar, as are most of the financial commodity contracts used by our marketing group. However, we pay for many of our purchases in Canadian dollars. We enter into US-dollar forward contracts and swaps to manage this exposure. Gains and losses on our US-dollar forward contracts and swaps are included in the Unaudited Consolidated Balance Sheet, and any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income. At June 30, 2007, the fair value of our US-dollar forward contracts and swaps was $2 million.
(d) Total carrying value of derivative contracts related to trading activities
Amounts related to derivative instruments held by our marketing operation are equal to fair value as we use mark-to-market accounting. The amounts are as follows:
June 30 December 31
2007 2006
----------------------------------------------------------------------------
Accounts Receivable 365 731
Deferred Charges and Other Assets (1) 208 153
-------------------------
Total Derivative Contract Assets 573 884
-------------------------
-------------------------
Accounts Payable and Accrued Liabilities 331 325
Deferred Credits and Other Liabilities (1) 111 199
-------------------------
Total Derivative Contract Liabilities 442 524
-------------------------
-------------------------
Total Derivative Contract Net Assets (2) 131 360
-------------------------
-------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) Comprised of $129 million (2006 - $372 million) related to commodity
contracts and gains of $2 million (2006 - losses of $12 million) related to
US-dollar forward contracts and swaps.
Our exchange-traded derivative contracts are subject to margin deposit requirements. We are required to advance cash to counterparties in order to satisfy their requirements. We have margin deposits of $96 million (December 31, 2006 - $197 million), which have been included in restricted cash and margin deposits on our Unaudited Consolidated Balance Sheet at June 30, 2007.
10. SHAREHOLDERS' EQUITY
Dividends
Dividends per common share for the three months ended June 30, 2007 were $0.025 (2006 - $0.025). Dividends per common share for the six months ended June 30, 2007 were $0.05 (2006 - $0.05). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.
11. EARNINGS PER COMMON SHARE
Our shareholders approved a split of our issued and outstanding common shares on a two-for-one basis at our annual and special meeting on April 26, 2007. All common share and per common share amounts have been retroactively restated to reflect this share split.
We calculate basic earnings per common share using net income and the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.
Three Months Six Months
Ended June 30 Ended June 30
(millions of shares) 2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted-average number of common shares
outstanding 527.0 524.2 526.5 523.8
Shares issuable pursuant to tandem options 26.9 28.4 27.6 28.8
Shares to be purchased from proceeds of
tandem options (15.6) (15.1) (15.4) (15.0)
-------------------------------
Weighted-average number of diluted common
shares outstanding 538.3 537.5 538.7 537.6
-------------------------------
-------------------------------
In calculating the weighted-average number of diluted common shares outstanding for the three and six months ended June 30, 2007, we excluded 36,000 and 37,667 options respectively, because their exercise price was greater than the average market price in those periods. In calculating the weighted-average number of diluted common shares outstanding for the three and six months ended June 30, 2006, all options were included because their exercise price was less than the quarterly average common share market price in the period. During the periods presented, outstanding stock options were the only potential dilutive instruments.
12. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization and
Impairment 360 260 694 526
Stock-Based Compensation (70) 4 (26) 112
Future Income Taxes 126 14 161 283
Change in Fair Value of Crude Oil Put
Options 4 (3) 20 1
Net Income Attributable to Non-Controlling
Interests 5 6 8 9
Other 22 12 25 34
-------------------------------
Total 447 293 882 965
-------------------------------
-------------------------------
(b) Changes in non-cash working capital
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Accounts Receivable (142) 8 (67) 837
Inventories and Supplies (244) (108) (179) (258)
Other Current Assets 15 16 11 21
Accounts Payable and Accrued Liabilities 54 (272) (4) (843)
Accrued Interest Payable 29 15 11 (2)
-------------------------------
Total (288) (341) (228) (245)
-------------------------------
-------------------------------
Relating to:
Operating Activities (304) (377) (272) (304)
Investing Activities 16 36 44 59
-------------------------------
Total (288) (341) (228) (245)
-------------------------------
-------------------------------
(c) Other cash flow information
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Interest Paid 55 50 156 130
Income Taxes Paid 100 138 157 208
-------------------------------
13. MARKETING AND OTHER
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Marketing Revenue, Net 284 293 531 730
Change in Fair Value of Crude Oil Put
Options (4) 3 (20) (1)
Interest 10 11 19 19
Foreign Exchange Losses (38) (27) (43) (48)
Other (1) 47 96 60 102
-------------------------------
Total 299 376 547 802
-------------------------------
-------------------------------
(1) Other income for the three and six months ended June 30, 2006 includes
$74 million of business interruption proceeds received from our insurers
relating to generator failures in 2005 at our UK oil and gas operations.
14. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the Audited Consolidated Financial Statements included in our 2006 Annual Report on Form 10-K, 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 the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.
15. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Energy Marketing, Syncrude and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2006 Annual Report on Form 10-K.
Three months ended June 30, 2007
Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------------
Net Sales 288 113 148 592 35
Marketing and Other 3 3 - 24 -
------------------------------------------------------
Total Revenues 291 116 148 616 35
Less: Expenses
Operating 42 42 26 53 2
Depreciation,
Depletion,
Amortization and
Impairment 64 41 62 158 3
Transportation and
Other 1 6 - - -
General and
Administrative(3) (4) 8 (5) (3) 1
Exploration 2 9 49 18 27(4)
Interest - - - - -
------------------------------------------------------
Income (Loss)
before Income Taxes 186 10 16 390 2
Less: Provision for
(Recovery of)
Income Taxes 64(5) 2 - 202 9
Less:
Non-Controlling
Interests - - - - -
------------------------------------------------------
Net Income (Loss) 122 8 16 188 (7)
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 441 4,543(6) 1,581 5,107 258
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 31 316 128 158 7
Exploration 5 12 49 17 16
Proved Property
Acquisitions - - - 45(8) -
------------------------------------------------------
36 328 177 220 23
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 2,260 5,920 2,878 4,702 241
Less: Accumulated
DD&A 2,012 1,521 1,406 636 77
------------------------------------------------------
Net Book Value 248 4,399(6) 1,472 4,066 164
------------------------------------------------------
------------------------------------------------------
Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 7 115 101 - 1,399
Marketing and Other 284 - 17 (32)(2) 299
------------------------------------------------------
Total Revenues 291 115 118 (32) 1,698
Less: Expenses
Operating 6 51 67 - 289
Depreciation,
Depletion,
Amortization and
Impairment 3 12 11 6 360
Transportation and
Other 189 4 8 2 210
General and
Administrative(3) 23 - 8 10 38
Exploration - - - - 105
Interest - - 3 43 46
------------------------------------------------------
Income (Loss)
before Income Taxes 70 48 21 (93) 650
Less: Provision for
(Recovery of)
Income Taxes 26 13 6 (45) 277
Less:
Non-Controlling
Interests - - 5 - 5
------------------------------------------------------
Net Income (Loss) 44 35 10 (48) 368
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 3,355(7) 1,186 495 228 17,194
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 1 8 14 12 675
Exploration - - - - 99
Proved Property
Acquisitions - - - - 45
------------------------------------------------------
1 8 14 12 819
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 229 1,314 802 303 18,649
Less: Accumulated
DD&A 52 196 444 158 6,502
------------------------------------------------------
Net Book Value 177 1,118 358 145 12,147
------------------------------------------------------
------------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $10 million, foreign exchange losses of $38
million and decrease in the fair value of crude oil put options of $4
million.
(3) Includes recovery of stock-based compensation of $55 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes Yemen cash taxes of $65 million.
(6) Includes costs of $3,028 million related to our Long Lake project, which
are not being depreciated, depleted or amortized.
(7) Approximately 81% of Marketing's identifiable assets are accounts
receivable and inventories.
(8) Includes acquisition of additional interests in the Scott and Telford
fields.
Six months ended June 30, 2007
Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------------
Net Sales 531 228 316 936 64
Marketing and Other 6 4 - 28 -
------------------------------------------------------
Total Revenues 537 232 316 964 64
Less: Expenses
Operating 84 81 54 106 4
Depreciation,
Depletion,
Amortization and
Impairment 122 82 146 272 6
Transportation and
Other 4 13 - - -
General and
Administrative(3) (3) 40 14 2 25
Exploration 5 14 62 38 35(4)
Interest - - - - -
------------------------------------------------------
Income (Loss)
before Income Taxes 325 2 40 546 (6)
Less: Provision for
(Recovery of)
Income Taxes 113(5) - 14 284 7
Less:
Non-Controlling
Interests - - - - -
------------------------------------------------------
Net Income (Loss) 212 2 26 262 (13)
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 441 4,543(6) 1,581 5,107 258
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 63 672 267 298 15
Exploration 10 45 63 63 26
Proved Property
Acquisitions - - - 46(8) -
------------------------------------------------------
73 717 330 407 41
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 2,260 5,920 2,878 4,702 241
Less: Accumulated
DD&A 2,012 1,521 1,406 636 77
------------------------------------------------------
Net Book Value 248 4,399(6) 1,472 4,066 164
------------------------------------------------------
------------------------------------------------------
Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 23 234 207 - 2,539
Marketing and Other 531 - 22 (44)(2) 547
------------------------------------------------------
Total Revenues 554 234 229 (44) 3,086
Less: Expenses
Operating 19 98 133 - 579
Depreciation,
Depletion,
Amortization and
Impairment 7 25 22 12 694
Transportation and
Other 409 9 19 2 456
General and
Administrative(3) 53 - 17 92 240
Exploration - - - - 154
Interest - - 6 88 94
------------------------------------------------------
Income (Loss)
before Income Taxes 66 102 32 (238) 869
Less: Provision for
(Recovery of)
Income Taxes 26 30 9 (111) 372
Less:
Non-Controlling
Interests - - 8 - 8
------------------------------------------------------
Net Income (Loss) 40 72 15 (127) 489
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 3,355(7) 1,186 495 228 17,194
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 1 15 26 20 1,377
Exploration - - - - 207
Proved Property
Acquisitions - - - - 46
------------------------------------------------------
1 15 26 20 1,630
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 229 1,314 802 303 18,649
Less: Accumulated
DD&A 52 196 444 158 6,502
------------------------------------------------------
Net Book Value 177 1,118 358 145 12,147
------------------------------------------------------
------------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $19 million, foreign exchange losses of $43
million and decrease in the fair value of crude oil put options of $20
million.
(3) Includes stock-based compensation expense of $61 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes Yemen cash taxes of $109 million.
(6) Includes costs of $3,028 million related to our Long Lake project, which
are not being depreciated, depleted or amortized.
(7) Approximately 81% of Marketing's identifiable assets are accounts
receivable and inventories.
(8) Includes acquisition of additional interests in the Scott and Telford
fields.
Three months ended June 30, 2006
Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------------
Net Sales 364 122 161 134 39
Marketing and Other 1 5 - 77(2) 1
------------------------------------------------------
Total Revenues 365 127 161 211 40
Less: Expenses
Operating 38 34 22 20 1
Depreciation,
Depletion,
Amortization and
Impairment 91 38 49 54 3
Transportation and
Other 1 1 - - -
General and
Administrative(4) - 9 10 2 9
Exploration - 8 15 8 15(5)
Interest - - - - -
------------------------------------------------------
Income (Loss)
before Income Taxes 235 37 65 127 12
Less: Provision for
(Recovery of)
Income Taxes 82(6) (20) 22 42 4
Less:
Non-Controlling
Interests - - - - -
------------------------------------------------------
Net Income (Loss) 153 57 43 85 8
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 540 3,105 1,437 5,081 173
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 28 309 80 159 4
Exploration 10 71 72 6 8
Proved Property
Acquisitions - - - - -
------------------------------------------------------
38 380 152 165 12
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 2,235 4,369 2,512 4,129 202
Less: Accumulated
DD&A 1,923 1,369 1,196 319 70
------------------------------------------------------
Net Book Value 312 3,000 1,316 3,810 132
------------------------------------------------------
------------------------------------------------------
Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 7 114 98 - 1,039
Marketing and Other 293 - 12 (13)(3) 376
------------------------------------------------------
Total Revenues 300 114 110 (13) 1,415
Less: Expenses
Operating 5 44 59 - 223
Depreciation,
Depletion,
Amortization and
Impairment 1 6 10 8 260
Transportation and
Other 186 5 10 - 203
General and
Administrative(4) 39 - 6 33 108
Exploration - - - - 46
Interest - - 3 8 11
------------------------------------------------------
Income (Loss)
before Income Taxes 69 59 22 (62) 564
Less: Provision for
(Recovery of)
Income Taxes 42 19 7 (48) 150
Less:
Non-Controlling
Interests - - 6 - 6
------------------------------------------------------
Net Income (Loss) 27 40 9 (14) 408
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 2,698(7) 1,177 462 295 14,968
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 34 20 8 10 652
Exploration - - - - 167
Proved Property
Acquisitions - - - - -
------------------------------------------------------
34 20 8 10 819
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 209 1,292 828 262 16,038
Less: Accumulated
DD&A 42 174 474 136 5,703
------------------------------------------------------
Net Book Value 167 1,118 354 126 10,335
------------------------------------------------------
------------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes proceeds of $74 million from business interruption insurance
claims for generator failures in 2005 at our UK oil and gas operations.
(3) Includes interest income of $11 million, foreign exchange losses of $27
million and increase in the fair value of crude oil put options of $3
million.
(4) Includes stock-based compensation expense of $11 million.
(5) Includes exploration activities primarily in Nigeria and Colombia.
(6) Includes Yemen cash taxes of $81 million.
(7) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
Six months ended June 30, 2006
Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------------
Net Sales 692 233 342 268 67
Marketing and Other 4 6 - 79(2) 1
------------------------------------------------------
Total Revenues 696 239 342 347 68
Less: Expenses
Operating 74 68 52 42 3
Depreciation,
Depletion,
Amortization and
Impairment 168 75 104 125 5
Transportation and
Other 3 11 - - -
General and
Administrative(4) 14 51 45 6 25
Exploration - 14 77 28 30(5)
Interest - - - - -
------------------------------------------------------
Income (Loss)
before Income Taxes 437 20 64 146 5
Less: Provision for
(Recovery of)
Income Taxes 153(6) (26) 22 324(7) 2
Less:
Non-Controlling
Interests - - - - -
------------------------------------------------------
Net Income (Loss) 284 46 42 (178) 3
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 540 3,105 1,437 5,081 173
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 75 634 144 279 13
Exploration 15 117 112 25 15
Proved Property
Acquisitions - 2 - 1 -
------------------------------------------------------
90 753 256 305 28
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 2,235 4,369 2,512 4,129 202
Less: Accumulated
DD&A 1,923 1,369 1,196 319 70
------------------------------------------------------
Net Book Value 312 3,000 1,316 3,810 132
------------------------------------------------------
------------------------------------------------------
Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 14 198 205 - 2,019
Marketing and Other 730 - 12 (30)(3) 802
------------------------------------------------------
Total Revenues 744 198 217 (30) 2,821
Less: Expenses
Operating 12 97 125 - 473
Depreciation,
Depletion,
Amortization and
Impairment 4 11 20 14 526
Transportation and
Other 418 11 20 - 463
General and
Administrative(4) 75 - 13 99 328
Exploration - - - - 149
Interest - - 5 15 20
------------------------------------------------------
Income (Loss)
before Income Taxes 235 79 34 (158) 862
Less: Provision for
(Recovery of)
Income Taxes 101 26 11 (85) 528
Less:
Non-Controlling
Interests - - 9 - 9
------------------------------------------------------
Net Income (Loss) 134 53 14 (73) 325
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 2,698(8) 1,177 462 295 14,968
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and
Other 35 57 10 17 1,264
Exploration - - - - 284
Proved Property
Acquisitions - - - - 3
------------------------------------------------------
35 57 10 17 1,551
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 209 1,292 828 262 16,038
Less: Accumulated
DD&A 42 174 474 136 5,703
------------------------------------------------------
Net Book Value 167 1,118 354 126 10,335
------------------------------------------------------
------------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes proceeds of $74 million from business interruption insurance
claims for generator failures in 2005 at our UK oil and gas operations.
(3) Includes interest income of $19 million, foreign exchange losses of $48
million and decrease in the fair value of crude oil put options of $1
million.
(4) Includes stock-based compensation expense of $156 million.
(5) Includes exploration activities primarily in Nigeria and Colombia.
(6) Includes Yemen cash taxes of $148 million.
(7) Includes future income tax expense of $277 million related to an
increase in the supplemental tax rate on oil and gas activities in the
United Kingdom.
(8) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
16. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and Balance Sheet and summaries of differences from Canadian GAAP are as follows:
(a) Unaudited Consolidated Statement of Income - US GAAP
For the Three and Six Months ended June 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except per share amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,399 1,039 2,539 2,019
Marketing and Other (i) 299 377 545 813
---------------------------------
1,698 1,416 3,084 2,832
---------------------------------
Expenses
Operating (ii) 296 225 592 477
Depreciation, Depletion, Amortization and
Impairment 360 260 694 526
Transportation and Other 210 203 456 463
General and Administrative (iv) 51 122 250 343
Exploration 105 46 154 149
Interest 46 11 94 20
---------------------------------
1,068 867 2,240 1,978
---------------------------------
Income before Income Taxes 630 549 844 854
---------------------------------
Provision for Income Taxes
Current 151 136 211 245
Deferred (i) - (iv) 120 10 153 4
---------------------------------
271 146 364 249
---------------------------------
Net Income before Non-Controlling Interests 359 403 480 605
Less: Net Income Attributable to
Non-Controlling Interests (5) (6) (8) (9)
---------------------------------
Net Income - US GAAP (1) 354 397 472 596
---------------------------------
---------------------------------
Earnings Per Common Share ($/share)
Basic (Note 11) 0.67 0.76 0.90 1.14
---------------------------------
---------------------------------
Diluted (Note 11) 0.66 0.74 0.88 1.11
---------------------------------
---------------------------------
(1) Reconciliation of Canadian and US GAAP Net Income
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net Income - Canadian GAAP 368 408 489 325
Impact of US Principles, Net of Income
Taxes:
Ineffective Portion of Cash Flow Hedges (i) - 1 (2) 7
Pre-operating Costs (ii) (5) (2) (8) (3)
Deferred Income Taxes (iii) - - - 277
Liability-based Stock Compensation Plans
(iv) (9) (10) (7) (10)
---------------------------------
Net Income - US GAAP 354 397 472 596
---------------------------------
---------------------------------
(b) Unaudited Consolidated Balance Sheet - US GAAP
June 30 December 31
(Cdn$ millions, except share amounts) 2007 2006
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 158 101
Restricted Cash and Margin Deposits 96 197
Accounts Receivable 2,861 2,976
Inventories and Supplies 857 786
Deferred Income Tax Asset 277 479
Other 51 67
---------------------------
Total Current Assets 4,300 4,606
---------------------------
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $6,895
(December 31, 2006 - $6,792) (ii); (vi) 12,087 11,692
Deferred Income Tax Assets 78 141
Deferred Charges and Other Assets 321 263
Goodwill 348 377
---------------------------
Total Assets 17,134 17,079
---------------------------
---------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Borrowings 61 158
Accounts Payable and Accrued Liabilities (iv) 3,700 3,839
Accrued Interest Payable 65 55
Dividends Payable 13 13
---------------------------
Total Current Liabilities 3,839 4,065
---------------------------
Long-Term Debt 4,852 4,618
Deferred Income Tax Liabilities (i) - (vi) 2,226 2,427
Asset Retirement Obligations 690 683
Deferred Credits and Liabilities (v) 502 597
Non-Controlling Interests 73 75
Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 527,149,918 shares
2006 - 525,026,412 shares 893 821
Contributed Surplus 5 4
Retained Earnings (i) - (vi) 4,363 3,945
Accumulated Other Comprehensive Income (i); (v) (309) (156)
---------------------------
Total Shareholders' Equity 4,952 4,614
---------------------------
Commitments, Contingencies and Guarantees
Total Liabilities and Shareholders' Equity 17,134 17,079
---------------------------
---------------------------
(c) Unaudited Consolidated Statement of Comprehensive Income - US GAAP
For the Three and Six Months Ended June 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Income - US GAAP 354 397 472 596
Other Comprehensive Income, Net of Income
Taxes:
Foreign Currency Translation Adjustment (86) (63) (92) (65)
Change in Mark to Market on Cash Flow
Hedges (i) - 6 (61) 20
---------------------------------
Comprehensive Income 268 340 319 551
---------------------------------
---------------------------------
(d) Unaudited Consolidated Statement of Accumulated Other Comprehensive
Income - US GAAP
June 30 December 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Foreign Currency Translation Adjustment (253) (161)
Mark to Market on Cash Flow Hedges (i) - 61
Unamortized Defined Benefit Pension Costs (v) (56) (56)
---------------------------
(309) (156)
---------------------------
---------------------------
Notes:
i. Under US GAAP, all derivative instruments are recognized on the balance sheet as either an asset or a liability measured at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. On January 1, 2007, we adopted the equivalent Canadian standard for derivative instruments.
Cash flow hedges
Changes in the fair value of derivatives that are designated as cash flow hedges are recognized in earnings in the same period as the hedged item. Any fair value change in a derivative before that period is recognized on the balance sheet. The effective portion of that change is recognized in other comprehensive income with any ineffectiveness recognized in net income during the period of change.
Future sale of gas inventory: At December 31, 2006, accounts receivable includes gains of $25 million on futures contracts and swaps we used to hedge commodity price risk on the future sale of our gas inventory. Gains of $23 million ($16 million, net of income taxes) related to the effective portion and deferred in AOCI at December 31, 2006, were recognized in marketing and other in the first quarter of 2007. The ineffective portion of the gains of $2 million ($2 million, net of income taxes) was recognized in marketing and other in 2006 under US GAAP. Under Canadian GAAP, the ineffective portion was recognized in net income in the first quarter of 2007.
At June 30, 2006, our US GAAP net income includes $11 million ($7 million, net of income taxes) relating to the ineffective portion of cash flow hedges.
Also included in AOCI at December 31, 2006 are gains of $65 million ($45 million, net of income taxes) related to de-designated cash flow hedges. These gains were recognized in marketing and other in the first quarter of 2007. Under Canadian GAAP, these deferred gains are included in accounts payable and accrued liabilities at December 31, 2006 and have been recognized in marketing and other income in the first quarter of 2007.
At June 30, 2007, there were no cash flow hedges in place.
Fair value hedges
Both the derivative instrument and the underlying commitment are recognized on the balance sheet at their fair value. The change in fair value of both is reflected in earnings. At June 30, 2007 and at December 31, 2006, we had no fair value hedges in place.
ii. Under Canadian GAAP, we defer certain development costs and all pre-operating revenues and costs to property, plant and equipment. Under US principles, these costs have been included in operating expenses. As a result:
- operating expenses include pre-operating costs of $7 million and $13 million for the three and six months ended June 30, 2007, respectively ($5 million and $8 million, respectively, net of income taxes) (2006 - $2 million and $4 million, respectively ($2 million and $3 million, respectively, net of income taxes)); and
- property, plant and equipment is lower under US GAAP by $41 million (December 31, 2006 - $28 million).
iii. Under US GAAP, enacted tax rates are used to calculate deferred income taxes, whereas under Canadian GAAP, substantively enacted rates are used. During the first quarter of 2006, the UK government substantively enacted increases to the supplementary tax on oil and gas activities from 10% to 20%, effective January 1, 2006. This created a $277 million future income tax expense during the first quarter of 2006 under Canadian GAAP.
iv. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. We are also required to accelerate the recognition of stock- based compensation expense for all stock-based awards made to our retirement-eligible employees under Canadian GAAP. However, under US GAAP, the accelerated recognition for such employees is only required for stock-based awards granted on or after January 1, 2006. As a result:
- general and administrative expense is higher by $13 million and $10 million for the three and six months ended June 30, 2007, respectively ($9 million and $7 million, respectively, net of income taxes) (2006 - higher by $14 million and $15 million for the three and six months ended June, respectively ($10 million and $10 million, respectively, net of income taxes)); and
- accounts payable and accrued liabilities are higher by $35 million as at June 30, 2007 (December 31, 2006 - $25 million).
v. On December 31, 2006, we adopted FASB Statement 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans (FAS 158). At June 30, 2007, the unfunded amount of our defined benefit pension plans was $81 million. This amount has been included in deferred credits and other liabilities and $56 million, net of income taxes has been included in AOCI. Prior to the adoption of FAS 158 on December 31, 2006, we included our minimum unfunded pension liability in deferred credits and other liabilities and in AOCI.
vi. On January 1, 2003, we adopted FASB Statement 143, Accounting for Asset Retirement Obligations (FAS 143) for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our property, plant and equipment under US GAAP being lower by $19 million.
Stock-based Compensation Expense for Retired and Retirement-Eligible Employees
Under US GAAP, we recognize stock-based compensation expense for our retired and retirement-eligible employees over an accelerated vesting period in accordance with the provisions of Statement 123(R) for stock-based awards granted to employees on or after January 1, 2006. For stock-based awards granted prior to the adoption of Statement 123(R), stock-based compensation expense for our retired and retirement-eligible employees is recognized over a graded vesting period. If we applied the accelerated vesting provisions of Statement 123(R) to stock-based awards granted to our retired and retirement-eligible employees prior to the adoption of Statement 123(R), there would be no material change to our stock-based compensation expense for the three and six months ended June 30, 2007 and 2006.
CHANGES IN ACCOUNTING POLICIES - US GAAP
Income Taxes
On January 1, 2007, we adopted FASB Interpretation 48 Accounting for Uncertainty in Income Taxes (FIN 48) with respect to FAS 109 Accounting for Income Taxes regarding accounting and disclosure for uncertain tax positions. On the adoption of FIN 48, we recorded a cumulative effect of a change in accounting principle of $28 million. This amount increased our deferred income tax liabilities, with a corresponding decrease to our retained earnings as at January 1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet. As at January 1 and June 30, 2007, the total amount of our unrecognized tax benefits was approximately $210 million, all of which, if recognized, would affect our effective tax rate. As at January 1 and June 30, 2007, the total amount of interest and penalties in relation to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP - Unaudited Consolidated Balance Sheet is approximately $9 million. We had no interest or penalties in the US GAAP - Unaudited Consolidated Statement of Income for the first half of 2007. Our income tax filings are subject to audit by taxation authorities and as at January 1 and June 30, 2007 the following tax years remained subject to examination; (i) Canada - 1985 to date, (ii) United Kingdom - 2002 to date and (iii) United States - 2003 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next twelve months.
NEW US ACCOUNTING PRONOUNCEMENTS
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement 157, Fair Value Measurements. Statement 157 defines fair value, establishes a framework for measuring fair value under US generally accepted accounting principles and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.
Effective December 31, 2006, we adopted the recognition and disclosure provisions of FASB Statement 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement also requires measurement of the funded status of a plan as of the balance sheet date. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. We do not expect the adoption of the change in measurement date in 2008 to have a material impact on our results of operations or financial position.
In February 2007, FASB issued Statement 159, The Fair Value Option for Financial Assets and Financial Liabilities. The statement allows for the elective measurement of eligible financial instruments and certain other items at fair value in order to mitigate volatility in reported earnings without having to apply complex and detailed hedge accounting rules. This statement is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the provisions of Statement 159 and have not yet determined the impact this statement will have on our results from operations or financial position.
Contacts:Michael J. Harris, CA
Vice President, Investor Relations
(403) 699-4688
or
Lavonne Zdunich, CA
Analyst, Investor Relations
(403) 699-5821
or
Sean Noe, P.Eng
Analyst, Investor Relations
(403) 699-4494
or
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
Website: www.nexeninc.com
Return to News Releases
Last Reviewed:
|
|
Privacy
