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Nexen Reports Strong Financial Results and Bitumen Production Ramping Up at Long Lake CALGARY, ALBERTA--(MARKET WIRE)--Apr 29, 2008 -- Nexen Inc. - First Quarter Highlights: - Quarterly cash flow of $1,039 million ($1.96/share), up 74% over Q1 2007 - Record quarterly earnings of $630 million ($1.19/share), up 421% over Q1 2007 - Quarterly dividend to shareholders doubled to $0.05 per common share - Quarterly production before royalties of 267,000 boe/d (up 12% over Q1 2007)-on track to meet annual production guidance - Buzzard continues to outperform-quarterly production averages 212,000 boe/d gross (91,500 boe/d net) - At Long Lake, bitumen production rates have exceeded 7,500 bbls/d (3,750 bbls/d net to us); upgrader construction is complete and commissioning underway - Encouraging results from northeast BC shale gas production tests
Three Months Ended Three Months Ended
March 31 December 31
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(Cdn$ millions) 2008 2007 2007
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Production (mboe/d)(1)
Before Royalties 267 238 262
After Royalties 222 191 214
Net Sales 1,870 1,140 1,597
Cash Flow from Operations(2) 1,039 598 1,079
Per Common Share ($/share)(2) 1.96 1.14 2.04
Net Income 630 121 194
Per Common Share ($/share) 1.19 0.23 0.37
Capital Investment, including
Acquisitions 786 811 870
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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. 8.Nexen delivered strong first quarter results, meeting production targets and achieving record earnings. We generated cash flow from operations of over one billion dollars for the second quarter in a row and our cash flow exceeded our capital investment by $253 million. Production averaged 267,000 boe/d (222,000 boe/d after royalties) as strong oil and gas production from our Buzzard field in the North Sea more than offset production outages at Syncrude. With solid production, attractive commodity prices and high operating margins, net income was a record $630 million. Cash flow from operations totalled $1,039 million after $392 million in current income taxes. The majority of the income taxes were in the UK where Buzzard generated excellent returns from strong volumes and high cash margins. Current taxes in the fourth quarter of 2007 were significantly lower at $87 million as income from Buzzard was sheltered by tax pools which are now substantially utilized. "I am pleased with our first quarter results as we accomplished what we set out to do," stated Charlie Fischer, Nexen's President and Chief Executive Officer. "We not only met our production and financial targets but completed construction at Long Lake and kept the project on schedule and within our current cost estimate."
Oil and Gas Production
Production before Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q1 2008 Q4 2007 Q1 2008 Q4 2007
------------------------------------------------------ --------------------
North Sea 110 96 110 96
Yemen 62 66 32 34
Canada 38 37 30 31
United States 32 34 28 29
Other Countries 6 6 5 5
Syncrude 19 23 17 19
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Total 267 262 222 214
--------------------- --------------------Our first quarter production volumes averaged 267,000 boe/d (222,000 boe/d after royalties) as all areas met or exceeded targets with the exception of Syncrude. During the quarter, Syncrude experienced downtime as a result of cold weather and unscheduled maintenance, reducing expected quarterly volumes by over 5,000 bbls/d. In the North Sea, Buzzard performed well and contributed 91,500 boe/d (212,000 boe/d gross) compared to 75,000 boe/d (174,000 boe/d gross) in the fourth quarter of 2007. After a year of operating experience, Buzzard start up issues are behind us and facility performance is now consistently exceeding our original design expectations. We have one week of scheduled maintenance downtime planned for Buzzard in each of the second and third quarters which will reduce production volumes slightly from the first quarter. In addition, the recent shut down of the Forties pipeline due to strike action at the Grangemouth refinery in Scotland caused us to shut-in production from Buzzard, Scott/Telford and Farragon. This will reduce our production volumes for the second quarter. For the next two quarters, we also expect Syncrude's volumes to remain at rates similar to the first quarter as two of their three cokers have planned turnarounds. "With strong first quarter production and the ramp up of Long Lake and Ettrick later this year, we are well positioned to meet our annual guidance range of 260,000 boe/d to 280,000 boe/d," commented Fischer. Long Lake Project Update During the quarter, we reached two major milestones as bitumen production began to ramp up and we completed construction of the upgrader. Total costs and project timing remain on schedule. We are injecting steam into the reservoir through all well pads and we started converting wells to SAGD production in late February. Currently 29 of 81 well pairs have been converted to SAGD. While early production rates are variable, total bitumen production is averaging 6,200 bbls/d with peak rates to date in excess of 7,500 bbls/d (3,750 bbls/d net to us). During the first quarter, we started up the first cogeneration unit which has reliably produced power in excess of 80 megawatts. Surplus power was sold into the Alberta power grid. We recently started up the second cogeneration unit and we expect it to be fully operational shortly. We expect to convert the remaining well pairs to SAGD by mid summer. This will allow bitumen production to grow to full rates over the next 6 to 12 months. The bitumen production capacity of the SAGD facilities is approximately 72,000 bbls/d (36,000 bbls/d net to us). "We are encouraged by the early production results and build up of reservoir pressure at Long Lake," said Fischer. "Based on two months of data, our bitumen production and SOR rates are meeting our expectations. We are confident we will have sufficient feedstock for the start up of the upgrader." With construction of the upgrader complete, we have turned over all units and systems to operations. We estimate that commissioning is over 50% complete and we plan to start introducing hydrocarbons into key processing units in May. Last week, while introducing oxygen into a liquid oxygen tank the tank roof was damaged. We are presently investigating the cause of the damage and implementing solutions to keep the upgrader start up process on track. Our start up schedule forecasts production of synthetic crude to ramp up to full rates over a 12 to 18 month period following initial upgrader start up. The upgrader is designed to produce approximately 60,000 bbls/d (30,000 bbls/d net to us) of premium synthetic crude. This project only develops about 10% of our oil sands leases. We plan to increase synthetic crude oil production as we sequentially develop our lands in 60,000 bbls/d (30,000 bbls/d net to us) phases using technologies developed at Long Lake. "We are excited about bringing our first integrated insitu oil sands project on stream in the coming months," stated Fischer. "The project, which is designed to produce one of the highest quality crudes in North America, is progressing as planned and once Long Lake is fully ramped up, we expect to enjoy a significant margin improvement over competing technologies as our energy costs will be significantly reduced. This project will generate significant value for our shareholders." Work continues on Phase 2 and our goal is to sanction this phase by year end. However, ultimate timing depends on accumulating sufficient operating history from Phase 1 and receiving clarity on proposed regulatory changes such as climate change. Proposed federal climate change regulations indicate a move towards carbon capture and sequestration. With the addition of shift reactors to future phases, our unique process allows for the pre-combustion capture of green house gas emissions for future sequestration. North Sea Update-Ettrick Development Progressing Towards First Oil Our Ettrick development in the North Sea is progressing towards first oil in the second half of 2008. The development will utilize a leased floating production, storage and offloading vessel (FPSO) designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. Construction of the FPSO is nearly complete and sea trials are expected to commence mid year. We have also identified a number of exploration opportunities in the immediate area that could be future tie-backs to Ettrick. We recently spud one of these opportunities, Blackbird, and have plans to drill another one later this year. We operate both Ettrick and Blackbird with an 80% working interest in each. We plan to drill six exploration wells in total in the UK North Sea before year end. "Our North Sea strategy is to grow our production here with exploration and exploitation opportunities near existing infrastructure," commented Fischer. "We currently have a number of satellite discoveries near our Buzzard, Scott/Telford, Ettrick and third party facilities that in aggregate have sizeable potential. We are currently assessing development options for these discoveries." Shale Gas Update Over the past 18 months, we have accumulated a substantial land position of approximately 123,000 net acres in an emerging Devonian shale gas play in the Horn River Basin in northeast British Columbia which has the potential to become one of the most significant shale gas plays in North America. We have a 100% working interest in these lands. Our capital program over the past two winters has primarily focused on the Dilly Creek area in the Horn River Basin where we have approximately 85,000 net acres. This shale gas play has been compared to the Barnett Shale in Texas by other operators in the area as it displays similar rock properties and play characteristics. The average gross shale thickness on our Dilly Creek lands is approximately 175 meters which is almost 50% thicker than the Barnett. We recently announced positive results from our winter program where we fraced three vertical wells and one horizontal well with encouraging results. Based on our assessment of the data we acquired, additional analysis conducted by third party consultants and assuming a 20% recovery factor, we estimate our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resources. Further appraisal activity is required before these estimates can be finalized and commerciality established. "There has been a lot of excitement over this play and we are very pleased to be a large part of it," commented Fischer. "We are well positioned with significant acreage that is surrounded by wells drilled by other major players in the area who have experienced strong production test results. Based on our winter program results, we believe our reservoir is comparable to those offsetting our lands." To further assess the potential of our lands, we are currently engaged in consultations with various stakeholders and are gearing up to conduct a summer drilling program consisting of two horizontal wells which will be fraced, completed and tied-in. We recently participated in the construction of an all-season road, providing us access to these well locations and approximately half of our Dilly Creek lands year round. Coalbed Methane (CBM) Development Continues In Canada, we continue to develop CBM from Mannville coals in the Fort Assiniboine area and well performance continues to meet expectations. The Government of Alberta recently provided clarification of the length adjustment to be used for calculation of the proposed royalties and we are reviewing our investment program in light of this announcement. Our production from this area averaged 34 mmcf/d for the quarter and we expect to exit the year around 46 mmcf/d as our existing wells dewater and production increases. Gulf of Mexico Update In the Eastern Gulf of Mexico, where we have interests in discoveries at Vicksburg and Shiloh, we increased our acreage position on an unpromoted basis by acquiring working interests of 25% in 33 blocks recently awarded to Shell from the lease sale in late 2007. A number of additional exploration opportunities have been identified in the region and plans are in place to spud one of these opportunities, Fredricksburg, in the next few months. We have a 20% interest in Shiloh, a 25% interest in Vicksburg and a 20% interest in Fredricksburg, with Shell operating all three. "We are excited about the Eastern Gulf of Mexico," stated Fischer. "When we combine discoveries at Vicksburg and Shiloh with the prospects we see on our land holdings, this area has the potential to become a significant part of our Gulf of Mexico business." Elsewhere in the Gulf of Mexico, we sanctioned development of our Longhorn discovery during the quarter. Development will consist of three subsea wells tied-back to the non-operated Crystal facility. First production is expected in 2009 with a peak production rate of approximately 200 mmcf/d gross. We have a 25% non-operated working interest and Eni is the operator. To date, we have not been able to find a rig with the capability of drilling a delineation well at Knotty Head. As a result, we plan to drill an appraisal well in mid 2009 when our first new deep-water drilling rig arrives. We have a 25% operated interest in the field. Offshore West Africa During the quarter, we commenced development of the Usan field, offshore Nigeria. The field development plan includes a floating production, storage and offloading vessel with a storage capacity of two million barrels of oil. All major contracts for deep-water facilities have been awarded and contractors are mobilizing for detailed engineering and project execution. Our capital investment is expected to be within the range of US$1.6 to US$2.0 billion over the development period, with an estimated 2008 capital commitment of approximately US$300 million. The Usan field is expected to come on stream in early 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us). The Usan field development is located in OML 138 and is covered by the original production sharing contract for OPL 222 issued in 1993, with the Nigerian National Petroleum Corporation as concessionaire. The contract conveys the right to develop and produce crude oil and continue with exploration activity. We are currently processing three-dimensional seismic in anticipation of further exploratory drilling in the area. The Usan field was discovered in 2002 and is located approximately 100 kilometers offshore in water depths ranging from 750 to 850 meters. Nexen has a 20% interest in exploration and development along with Elf Petroleum Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%). Excess Cash Flow In 2008, we expect to generate substantial cash flow in excess of capital investment that can be used to reduce debt, fund additional capital investment programs and repurchase shares. "As we look to invest our cash flow, we consider all options to create additional value for shareholders," commented Fischer. Increased Quarterly Dividend The Board of Directors has declared an increase in the quarterly dividend to $0.05 per common share payable July 1, 2008, to shareholders of record on June 10, 2008. This doubles the dividend from the previous rate. 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, Western Canada (including the Athabasca oil sands of Alberta and unconventional gas resource plays such as coalbed methane and shale gas), deep-water Gulf of Mexico, offshore West Africa and the Middle East. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity, governance and environmental protection. Information with respect to forward-looking statements and cautionary notes is set out below. 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: April 29, 2008 Time: 12:30 p.m. Mountain Time (2:30 p.m. Eastern Time) To listen to the conference call, please call one of the following: 416-641-2140 (Toronto) 800-952-4972 (North American toll-free) 800-6578-9898 (Global toll-free) A replay of the call will be available for two weeks starting at 2:30 p.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 3250781 followed by the pound sign. A live and on demand webcast of the conference call will be available at www.nexeninc.com. 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) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information ("forward-looking statements") are generally identifiable by the terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook" or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future cost recovery oil revenues from our Yemen operations, future capital expenditures and their allocation to exploration and development activities, future earnings, 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 or resources, expected finding and development costs, expected operating costs, future demand for chemicals products, estimates on a per share basis, sales, 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. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. 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 including changes to taxes or royalties, changes in 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. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 2007 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 disclosure, 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. Under SEC regulations, we are required to recognize bitumen reserves rather than the upgraded premium synthetic crude oil we will produce and sell from Long Lake. 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 of 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 2007 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. Because reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery. Please note that 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. Resources Nexen's estimates of contingent resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe contingent resources as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program results, drilling and completions optimization, stakeholder and regulatory approval of future drilling and infrastructure plans, access to required infrastructure, economic fiscal terms, and general uncertainties associated with this early stage of evaluation. The estimated range of contingent resources reflects conservative and optimistic likelihoods of recovery. However, there is no certainty that it will be commercially viable to produce any portion of these contingent resources. Nexen's estimates of discovered resources (equivalent to discovered petroleum initially-in-place) are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe discovered resources as those quantities of petroleum estimated, as of a given date, to be contained in known accumulations prior to production. Discovered resources do not represent recoverable volumes. Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. In this disclosure, 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
Ended March 31
(Cdn$ millions) 2008 2007
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Net Sales 1,870 1,140
Cash Flow from Operations 1,039 598
Per Common Share ($/share) (1) 1.96 1.14
Net Income 630 121
Per Common Share ($/share) (1) 1.19 0.23
Capital Investment, including Acquisitions (2) 786 811
Net Debt (3) 4,059 4,939
Common Shares Outstanding (millions of shares) (1) 529.4 526.4
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(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
Ended March 31
(Cdn$ millions) 2008 2007
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Oil & Gas and Syncrude
Yemen (2) 165 158
Canada 86 44
United States 147 133
United Kingdom 880 291
Other Countries 34 7
Marketing 13 1
Syncrude 90 67
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1,415 701
Chemicals 13 23
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1,428 724
Interest and Other Corporate Items (64) (110)
Income Taxes (3) (325) (16)
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Cash Flow from Operations (1) 1,039 598
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(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 and excludes items of a non-recurring nature.
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.
Three Months
Ended March 31
(Cdn$ millions) 2008 2007
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Cash Flow from Operating Activities 1,168 448
Changes in Non-Cash Working Capital (140) (32)
Other 17 189
Amortization of Premium for Crude Oil Put Options (6) (7)
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Cash Flow from Operations 1,039 598
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Weighted-average Number of Common Shares Outstanding
(millions of shares) 528.9 526.0
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Cash Flow from Operations Per Common Share ($/share) 1.96 1.14
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(2) After in-country cash taxes of $67 million for the three months ended
March 31, 2008 (2007 - $44 million).
(3) Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months
Ended March 31
2008 2007
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Crude Oil and NGLs (mbbls/d)
Yemen 62.2 77.1
Canada 16.9 17.8
United States 13.7 21.6
United Kingdom 106.0 55.6
Other Countries 6.0 5.8
Syncrude (mbbls/d) (2) 19.3 21.4
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224.1 199.3
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Natural Gas (mmcf/d)
Canada 127 118
United States 112 101
United Kingdom 21 14
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260 233
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Total Production (mboe/d) 267 238
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Production Volumes (after royalties)
Three Months
Ended March 31
2008 2007
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Crude Oil and NGLs (mbbls/d)
Yemen 31.8 45.0
Canada 12.9 14.2
United States 12.0 19.3
United Kingdom 106.0 55.6
Other Countries 5.5 5.4
Syncrude (mbbls/d) (2) 17.0 18.9
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185.2 158.4
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Natural Gas (mmcf/d)
Canada 107 95
United States 95 86
United Kingdom 21 14
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223 195
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Total Production (mboe/d) 222 191
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Notes:
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Considered a mining operation for US reporting purposes.
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Quarters Total
- 2008 Quarters - 2007 Year
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(all dollar amounts in Cdn$
unless noted) 1st 1st 2nd 3rd 4th 2007
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PRICES:
WTI Crude Oil (US$/bbl) 97.90 58.16 65.03 75.38 90.69 72.31
Nexen Average - Oil (Cdn$/bbl) 93.00 61.69 72.27 75.86 82.80 73.43
NYMEX Natural Gas (US$/mmbtu) 8.75 7.18 7.66 6.24 7.39 7.12
Nexen Average - Gas (Cdn$/mcf) 7.97 7.58 7.52 5.80 6.47 6.81
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NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 16.2 17.8 17.2 16.9 16.4 17.1
Price Received ($/bbl) 65.94 41.71 41.89 46.76 46.07 44.07
Royalties & Other 16.65 9.16 9.52 10.93 10.04 9.91
Operating Costs 15.76 13.65 15.14 14.53 15.22 14.62
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Netback 33.53 18.90 17.23 21.30 20.81 19.54
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Canada - Natural Gas
Sales (mmcf/d) 127 118 116 112 124 118
Price Received ($/mcf) 7.57 7.16 7.06 5.17 5.88 6.32
Royalties & Other 1.18 1.26 1.09 0.78 0.86 1.00
Operating Costs 1.67 1.59 1.81 2.52 1.71 1.90
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Netback 4.72 4.31 4.16 1.87 3.31 3.42
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Yemen
Sales (mbbls/d) 62.5 77.5 72.7 69.9 66.2 71.5
Price Received ($/bbl) 96.57 63.02 77.34 78.27 88.24 76.29
Royalties & Other 48.07 28.17 33.84 34.73 43.04 34.69
Operating Costs 7.76 6.07 6.29 6.72 7.24 6.56
In-country Taxes 11.82 6.38 9.89 10.03 12.18 9.52
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Netback 28.92 22.40 27.32 26.79 25.78 25.52
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Syncrude
Sales (mbbls/d) 19.3 21.4 19.0 25.2 22.6 22.1
Price Received ($/bbl) 101.70 70.03 77.12 82.09 88.33 79.76
Royalties & Other 11.93 8.26 10.33 13.42 15.33 12.02
Operating Costs 35.16 24.40 29.91 22.37 27.52 25.80
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Netback 54.61 37.37 36.88 46.30 45.48 41.94
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(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
Quarters Total
- 2008 Quarters - 2007 Year
----------------------------------------------------------------------------
(all dollar amounts in Cdn$
unless noted) 1st 1st 2nd 3rd 4th 2007
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United States
Crude Oil:
Sales (mbbls/d) 13.7 21.6 16.0 14.1 13.9 16.4
Price Received ($/bbl) 94.07 58.49 68.18 74.43 84.33 69.83
Natural Gas:
Sales (mmcf/d) 112 101 86 98 119 101
Price Received ($/mcf) 9.03 8.58 8.85 6.75 7.27 7.80
Total Sales Volume (mboe/d) 32.4 38.4 30.4 30.5 33.8 33.3
Price Received ($/boe) 71.10 55.44 61.04 56.28 60.32 58.16
Royalties & Other 9.53 6.78 7.71 7.28 8.13 7.45
Operating Costs 8.20 8.11 9.46 7.40 8.78 8.43
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Netback 53.37 40.55 43.87 41.60 43.41 42.28
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United Kingdom
Crude Oil:
Sales (mbbls/d) 108.9 58.8 87.2 83.6 94.5 81.1
Price Received ($/bbl) 93.38 64.33 74.07 78.06 84.06 76.30
Natural Gas:
Sales (mmcf/d) 22 13 13 16 21 16
Price Received ($/mcf) 6.82 3.87 3.32 4.99 5.84 4.71
Total Sales Volume (mboe/d) 112.6 60.8 89.3 86.3 98.0 83.7
Price Received ($/boe) 91.67 62.92 72.75 76.56 82.29 74.79
Operating Costs 5.67 9.60 6.59 6.28 6.23 6.94
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Netback 86.00 53.32 66.16 70.28 76.06 67.85
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Other Countries
Sales (mbbls/d) 6.0 5.8 6.2 6.5 6.2 6.2
Price Received ($/bbl) 91.85 59.81 68.04 76.29 79.74 71.29
Royalties & Other 7.46 4.80 5.62 6.46 6.60 5.90
Operating Costs 4.74 2.97 3.39 3.34 4.13 3.45
----------------------------------------------------------------------------
Netback 79.65 52.04 59.03 66.49 69.01 61.94
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 270.1 241.5 254.1 253.9 263.9 253.4
Price Received ($/boe) 85.90 59.13 68.48 69.82 75.50 68.46
Royalties & Other 14.87 12.26 12.65 13.02 14.37 13.10
Operating Costs 9.46 9.67 9.41 9.26 9.46 9.45
In-country Taxes 2.74 2.05 2.83 2.76 3.05 2.69
----------------------------------------------------------------------------
Netback 58.83 35.15 43.59 44.78 48.62 43.22
----------------------------------------------------------------------------
(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 Months Ended March 31
(Cdn$ millions, except per share amounts) 2008 2007
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,870 1,140
Marketing and Other (Note 15) 222 248
------------------
2,092 1,388
------------------
Expenses
Operating 309 290
Depreciation, Depletion, Amortization and Impairment 364 334
Transportation and Other 205 246
General and Administrative 55 202
Exploration 32 49
Interest (Note 6) 27 48
------------------
992 1,169
------------------
Income before Income Taxes 1,100 219
------------------
Provision for Income Taxes
Current 392 60
Future 77 35
------------------
469 95
------------------
Net Income before Non-Controlling Interests 631 124
Less: Net Income Attributable to Non-Controlling
Interests (1) (3)
------------------
Net Income 630 121
------------------
------------------
Earnings Per Common Share ($/share)
Basic (Note 13) 1.19 0.23
------------------
------------------
Diluted (Note 13) 1.17 0.22
------------------
------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Balance Sheet
March 31 December 31
(Cdn$ millions, except share amounts) 2008 2007
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 524 206
Restricted Cash 75 203
Accounts Receivable (Note 2) 4,041 3,502
Inventories and Supplies (Note 3) 755 659
Future Income Tax Assets 25 18
Other 84 71
--------------------
Total Current Assets 5,504 4,659
--------------------
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $7,703
(December 31, 2007 - $7,195) 13,139 12,498
Future Income Tax Assets 263 268
Deferred Charges and Other Assets (Note 4) 418 324
Goodwill 337 326
--------------------
Total Assets 19,661 18,075
--------------------
--------------------
Liabilities and Shareholders' Equity
Current Liabilities
Current Portion of Long-Term Debt (Note 6) 125 -
Accounts Payable and Accrued Liabilities 4,894 4,180
Accrued Interest Payable 67 54
Dividends Payable 13 13
--------------------
Total Current Liabilities 5,099 4,247
--------------------
Long-Term Debt (Note 6) 4,458 4,610
Future Income Tax Liabilities 2,415 2,290
Asset Retirement Obligations (Note 8) 814 792
Deferred Credits and Other Liabilities (Note 9) 525 459
Non-Controlling Interests 64 67
Shareholders' Equity (Note 12)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2008 - 529,439,432 shares
2007 - 528,304,813 shares 949 917
Contributed Surplus 3 3
Retained Earnings 5,600 4,983
Accumulated Other Comprehensive Loss (266) (293)
--------------------
Total Shareholders' Equity 6,286 5,610
--------------------
Commitments, Contingencies and Guarantees (Note 16)
--------------------
Total Liabilities and Shareholders' Equity 19,661 18,075
--------------------
--------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three Months Ended March 31
(Cdn$ millions) 2008 2007
----------------------------------------------------------------------------
Operating Activities
Net Income 630 121
Charges and Credits to Income not Involving Cash (Note 14) 383 435
Exploration Expense 32 49
Changes in Non-Cash Working Capital (Note 14) 140 32
Other (17) (189)
-----------------
1,168 448
Financing Activities
(Repayment of) Proceeds from Term Credit Facilities, Net (228) 366
Proceeds from Term Credit Facilities of Canexus 8 18
Repayment of Short-Term Borrowings, Net - (48)
Dividends on Common Shares (13) (13)
Issue of Common Shares and Exercise of Stock Options 26 29
Other (4) (7)
-----------------
(211) 345
Investing Activities
Capital Expenditures
Exploration and Development (769) (790)
Proved Property Acquisitions - (1)
Chemicals, Corporate and Other (17) (20)
Changes in Restricted Cash 121 16
Changes in Non-Cash Working Capital (Note 14) 22 28
Other (27) (4)
-----------------
(670) (771)
Effect of Exchange Rate Changes on Cash
and Cash Equivalents 31 (13)
-----------------
Increase in Cash and Cash Equivalents 318 9
Cash and Cash Equivalents - Beginning of Period 206 101
-----------------
Cash and Cash Equivalents - End of Period 524 110
-----------------
-----------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Shareholders' Equity
For the Three Months Ended March 31
(Cdn$ millions) 2008 2007
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 917 821
Issue of Common Shares 20 21
Proceeds from Tandem Options Exercised for Shares 6 8
Accrued Liability Relating to Tandem Options Exercised
for Shares 6 16
-----------------
Balance at End of Period 949 866
-----------------
-----------------
Contributed Surplus
Balance at Beginning and End of Period 3 4
-----------------
-----------------
Retained Earnings
Balance at Beginning of Period 4,983 3,972
Net Income 630 121
Dividends on Common Shares (Note 12) (13) (13)
-----------------
Balance at End of Period 5,600 4,080
-----------------
-----------------
Accumulated Other Comprehensive Loss
Balance at Beginning of Period (293) (161)
Opening Derivatives Designated as Cash Flow Hedges - 61
Other Comprehensive Income (Loss) 27 (67)
-----------------
Balance at End of Period (266) (167)
-----------------
-----------------
Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three months Ended March 31
(Cdn$ millions) 2008 2007
----------------------------------------------------------------------------
Net Income 630 121
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment:
Net Gains (Losses) on Investment in Self-Sustaining
Foreign Operations 186 (58)
Net Gains (Losses) on Hedges of Self-Sustaining
Foreign Operations (1) (159) 50
Realized Translation Adjustments Recognized in Net
Income (2) - 2
Cash Flow Hedges:
Realized Mark-to-Market Gains Recognized in Net Income - (61)
-----------------
Other Comprehensive Income (Loss), Net of Income Taxes 27 (67)
-----------------
Comprehensive Income 657 54
-----------------
-----------------
(1) Net of income tax expense for the three months ended March 31, 2008 of
$23 million (2007 - $9 million recovery).
(2) Net of income tax expense for the three months ended March 31, 2008 of
$nil (2007 - $1 million expense).
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Consolidated Financial Statements
Cdn$ millions, except as noted1. 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 18. 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 March 31, 2008 and December 31, 2007 and the results of our operations and our cash flows for the three months ended March 31, 2008 and 2007. 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 months ended March 31, 2008 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2008. These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2007 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 2007 Annual Report on Form 10-K. Change in Accounting Policies Inventories In 2007, we adopted CICA Section 3031 Inventories issued by the Canadian Accounting Standards Board (AcSB). Effective October 1, 2007, we began carrying the commodity inventories held for trading by our energy marketing group at fair value, less any costs to sell. This standard was adopted prospectively and our results for the first three months of 2007 have not been restated for this change in accounting policy. Capital Disclosures On January 1, 2008, we prospectively adopted CICA Section 1535 Capital Disclosures issued by the AcSB. This Section establishes standards for disclosing information about an entity's objectives, policies and processes for managing its capital structure. The disclosures have been included in Note 7. Financial Instruments Disclosures and Presentation On January 1, 2008, we prospectively adopted the following new standards issued by the AcSB: Financial Instruments - Disclosure (Section 3862) and Financial Instruments - Presentation (Section 3863). These accounting standards replaced Financial Instruments - Disclosure and Presentation (Section 3861). The disclosures required by Section 3862 provide additional information on the risks associated with our financial instruments and how we manage those risks. The additional disclosures required by these standards are provided in Notes 10 and 11. New Accounting Pronouncements In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. We are currently evaluating the impact these sections will have on our results of operations and financial position. In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards (IFRS) by 2011 and we will be required to report according to IFRS standards for the year ended December 31, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures.
2. ACCOUNTS RECEIVABLE
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Trade
Marketing 2,907 2,501
Oil and Gas 931 819
Chemicals and Other 64 60
-------------------------
3,902 3,380
Non-Trade 149 132
-------------------------
4,051 3,512
Allowance for Doubtful Receivables (10) (10)
-------------------------
Total 4,041 3,502
-------------------------
-------------------------
3. INVENTORIES AND SUPPLIES
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Finished Products
Marketing 659 577
Oil and Gas 20 14
Chemicals and Other 16 13
-------------------------
695 604
Work in Process 4 3
Field Supplies 56 52
-------------------------
Total 755 659
-------------------------
-------------------------
4. DEFERRED CHARGES AND OTHER ASSETS
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts
(Note 10) 294 248
Long-Term Capital Prepayments 38 9
Crude Oil Put Options and Natural
Gas Swaps (Note 10) 18 -
Asset Retirement Remediation Fund 13 13
Other 55 54
-------------------------
Total 418 324
-------------------------
-------------------------5. SUSPENDED WELL COSTS The following table shows the changes in capitalized exploratory well costs during the three months ended March 31, 2008 and the year ended December 31, 2007, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Capitalized exploratory well costs are included in property, plant & equipment.
Three Year
Months Ended Ended
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Balance at Beginning of Period 326 226
Additions to Capitalized Exploratory Well Costs
Pending the Determination of Proved Reserves 49 215
Capitalized Exploratory Well Costs
Charged to Expense - (10)
Transfers to Wells, Facilities and Equipment
Based on Determination of Proved Reserves - (74)
Effects of Foreign Exchange 7 (31)
-------------------------
Balance at End of Period 382 326
-------------------------
-------------------------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.
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 195 202
Capitalized for a Period of Greater than One Year 187 124
-------------------------
Balance at End of Period 382 326
-------------------------
-------------------------
Number of Projects that have Exploratory Well Costs
Capitalized for a Period Greater than One Year 8 5
-------------------------As at March 31, 2008, we have exploratory costs that have been capitalized for more than one year relating to our interest in four exploratory blocks in the North Sea ($55 million), an exploratory block in the Gulf of Mexico ($54 million), our coalbed methane exploratory activities in Canada ($41 million), exploratory activities on Block 51 in Yemen ($19 million) and our interest in an exploratory block, offshore Nigeria ($18 million). These costs relate to projects with successful exploration wells for which we have not been able to record proved reserves. 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
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Term Credit Facilities (a) - 211
Canexus Limited Partnership Term Credit
Facilities (US$213 million) 218 202
Medium-Term Notes, due 2008 (b) 125 125
Notes, due 2013 (US$500 million) 514 494
Notes, due 2015 (US$250 million) 257 247
Notes, due 2017 (US$250 million) 257 247
Notes, due 2028 (US$200 million) 205 198
Notes, due 2032 (US$500 million) 514 494
Notes, due 2035 (US$790 million) 812 781
Notes, due 2037 (US$1,250 million) 1,285 1,235
Subordinated Debentures, due 2043 (US$460 million) 473 454
-------------------------
4,660 4,688
Less: Unamortized Debt Issue Costs (77) (78)
-------------------------
4,583 4,610
Less: Current Portion of Long-Term Debt (b) (125) -
-------------------------
4,458 4,610
-------------------------
-------------------------(a) Term credit facilities We have unsecured term credit facilities of US$3 billion available to 2012, none of which were drawn at March 31, 2008 (December 31, 2007 - US$214 million). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 3.9% for the three months ended March 31, 2008 (2007 - 5.9%). At March 31, 2008, $296 million of these facilities were utilized to support outstanding letters of credit (December 31, 2007 - $283 million). (b) Medium-Term Notes, due 2008 During October 1997, we issued $125 million of notes. Interest is payable semi-annually at a rate of 6.3% and the principal is to be repaid in June 2008. At December 31, 2007 this amount was not included in current liabilities as we expected to repay the principal using our term credit facilities. During the quarter, we reclassified this obligation to current liabilities as we now expect to repay this amount using our existing cash on hand.
(c) Interest expense
Three Months
Ended March 31
2008 2007
---------------------------------------------------------------------------
Long-Term Debt 76 81
Other 4 5
-------------------------
80 86
Less: Capitalized (53) (38)
-------------------------
Total 27 48
-------------------------
-------------------------Capitalized interest relates to and is included as part of the cost of our oil and gas properties under development. The capitalization rates are based on our weighted-average cost of borrowings. (d) Short-term borrowings Nexen has uncommitted, unsecured credit facilities of approximately $666 million, none of which were drawn at March 31, 2008 (December 31, 2007 - nil). We have utilized $44 million of these facilities to support outstanding letters of credit at March 31, 2008 (December 31, 2007 - $196 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 4.3% for the three months ended March 31, 2008 (2007 - 5.9%). 7. CAPITAL DISCLOSURES Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for our energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects, which require significant capital investment prior to cash flow generation, and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given year. As such, our financing needs depend on where we are in a particular development cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at: - maintaining an appropriate balance between short-term debt, long-term debt and equity, such as using longer-term senior and subordinated debt securities to minimize near-term refinancing risks; - maintaining sufficient undrawn committed credit capacity to provide liquidity; - ensuring ample covenant room permitting us to draw on our credit lines as required; - maintaining a level of leverage with sufficient room for increases when necessary; and - ensuring we maintain a credit rating that is appropriate for our circumstances. We have the ability to make adjustments to our capital structure by issuing additional equity or debt, controlling the amount we return to shareholders and making adjustments to our capital investment programs. Our capital consists of shareholders' equity, short-term and long-term debt and cash and cash equivalents (excluding restricted cash) as follows:
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Net Debt (1)
Bank Debt 218 413
Public Senior Notes 3,907 3,758
-------------------------
Senior Debt 4,125 4,171
Subordinated Debt 458 439
-------------------------
Total Debt 4,583 4,610
Less: Cash and Cash Equivalents (524) (206)
-------------------------
Total Net Debt 4,059 4,404
-------------------------
-------------------------
Shareholders' Equity 6,286 5,610
-------------------------
-------------------------
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.We monitor our capital structure by reviewing the ratio of net debt to cash flow from operating activities and interest coverage on a trailing 12 month basis that we feel are appropriate for Nexen. We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure which is calculated using the GAAP measure of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash). For the twelve months ending March 31, 2008 our net debt to cash flow from operating activities ratio was 1.1 times compared to 1.6 times at December 31, 2007. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we devise a strategy to reduce our leverage and lower this ratio back to target levels. In the past, each time we exceeded our internal net debt to cash flow from operating activities target band, we successfully brought our leverage down through asset sales and capital management. Our interest coverage ratio allows us to monitor our ability to meet the interest requirements of our capital and consequently the level, terms and condition of our debt profile. The higher the interest coverage, the better positioned we are to finance our longer-term investment projects. Our interest coverage strengthened in 2008 from 12.1 times at the end of 2007 to 14.4 times at March 31, as our earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) increased from strong production and high commodity prices. Interest coverage is calculated by dividing our twelve-month trailing EBITDA by interest expense before capitalized interest. EBITDA is a non-GAAP measure which is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A and other non-cash expenses. The calculation of EBITDA is set out in the following table.
Twelve Months Twelve Months
Ended Ended
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Net Income 1,595 1,086
Add:
Interest Expense 147 168
Provision for Income Taxes 1,166 792
Depreciation, Depletion, Amortization
and Impairment 1,797 1,767
Exploration Expense 309 326
Other Non-cash Expenses (176) (52)
-------------------------
EBITDA 4,838 4,087
-------------------------
-------------------------8. ASSET RETIREMENT OBLIGATIONS Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment are as follows:
Three Year
Months Ended Ended
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Balance at Beginning of Period 832 704
Obligations Incurred with Development Activities 2 105
Expenditures Made on Asset Retirements (13) (23)
Accretion 13 44
Revisions to Estimates (1) 79
Effects of Foreign Exchange 21 (77)
-------------------------
Balance at End of Period (1),(2) 854 832
-------------------------
-------------------------
(1)Obligations due within 12 months of $40 million (December 31, 2007 - $40
million) have been included in accounts payable and accrued liabilities.
(2)Obligations relating to our oil and gas activities amount to $807
million (December 31, 2007 - $786 million) and obligations relating to
our chemicals business amount to $47 million (December 31, 2007 - $46
million).Our total estimated undiscounted asset retirement obligations amount to $2,200 million (December 31, 2007 - $2,165 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.9%. Approximately $139 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 obligation to remediate becomes determinable.
9. DEFERRED CREDITS AND OTHER LIABILITIES
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 10) 225 163
Deferred Transportation Revenue 73 82
Defined Benefit Pension Obligations 58 57
Capital Lease Obligations 53 52
Fixed-Price Natural Gas Contracts (Note 10) 49 48
Other 67 57
-------------------------
Total 525 459
-------------------------
-------------------------10. FINANCIAL INSTRUMENTS Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments including accounts receivable, accounts payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt are carried at cost or amortized cost. The carrying value of our short-term receivables and payables approximates their fair value because the instruments are near maturity. In our energy marketing group, we enter into contracts to purchase and sell crude oil and natural gas and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). Occasionally, we use derivatives such as put options to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. Refer to the derivatives section below for details of our derivatives and fair values as at March 31, 2008. The fair value is included with accounts receivable or payable and they are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income. We carry our long-term debt at amortized cost using the effective interest rate method. At March 31, 2008, the estimated fair value of our long-term debt was $4,578 million (December 31, 2007 - $4,692 million) as compared to the carrying value of $4,583 million (December 31, 2007 - $4,610 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers. Derivatives a) Total carrying value of derivative contracts related to trading activities The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Accounts Receivable 595 334
Deferred Charges and Other Assets (1) 294 248
-------------------------
Total Derivative Assets 889 582
-------------------------
-------------------------
Accounts Payable and Accrued Liabilities 543 413
Deferred Credits and Other Liabilities (1) 225 163
-------------------------
Total Derivative Liabilities 768 576
-------------------------
-------------------------
Total Net Derivatives related to
Trading Activities 121 6
-------------------------
-------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.b) Total carrying value of derivative contracts related to non-trading activities The fair value and carrying amounts related to derivative instruments related to non-trading activities are as follows:
March 31 December 31
2008 2007
---------------------------------------------------------------------------
Accounts Receivable 8 -
Deferred Charges and Other Assets (1) 18 1
-------------------------
Total Derivative Assets 26 1
-------------------------
-------------------------
Accounts Payable and Accrued Liabilities 36 28
Deferred Credits and Other Liabilities (1) 49 51
-------------------------
Total Derivative Liabilities 85 79
-------------------------
-------------------------
Total Net Derivatives related to
Non-Trading Activities (59) (78)
-------------------------
-------------------------
(1)These derivative contracts settle beyond 12 months and are considered
non-current.Crude oil put options In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production. These options establish an annual average Dated Brent floor price of $60/bbl on these volumes. In 2007, we purchased put options on 36 million barrels or approximately 100,000 bbls/d of our 2008 crude oil production. These options establish an annual average Dated Brent floor price of US$50/bbl on these volumes. The put options are carried at fair value within amounts receivable and are classified as long-term or short-term based on their anticipated settlement date. Any changes in fair value are included in marketing and other income.
Average
Notional Floor Fair
Volumes Term Price Value
---------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$
millions)
Dated Brent Crude Oil
Put Options 100,000 2008 50 -
Dated Brent Crude Oil
Put Options 70,000 2009 60 14
----------
14
----------
----------Fixed-price natural gas contracts and natural gas swaps We have fixed-price natural gas sales contracts and offsetting natural gas swaps that are not included in our trading activities. These sales contracts and swaps are carried at fair value and are included with amounts receivable or payable. They are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.
Notional Average Fair
Volumes Term Price Value
---------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$
millions)
Fixed-Price Natural
Gas Contracts 15,514 2008 2.46 (36)
15,514 2009 - 2010 2.56 - 2.77 (49)
Natural Gas Swaps 15,514 2008 7.60 8
15,514 2009 - 2010 7.60 4
----------
(73)
----------
----------c) Fair Value of Derivatives Wherever possible, the estimated fair value of our derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. As a basis for establishing fair value, we utilize a mid-market pricing convention between bid and ask and then adjust our pricing to the ask price when we have a net open sell and the bid price when we have a net open buy. We incorporate the credit risk associated with counterparty default into our estimates of fair value. Inputs to fair valuations may be readily observable, market-corroborated, or generally unobservable. We utilize valuation techniques that maximize the use of observable inputs wherever possible and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used. We classify our derivatives according to the following hierarchy based on the amount of observable inputs used to value the instruments. - Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange and the International Petroleum Exchange. - Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors, and broker quotations, which can be observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes. - Level 3 - Valuations in this level are based on inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily include extrapolation of observable future prices to similar locations, similar instruments or later time periods. The following table includes our derivatives that are carried at fair value on a recurring basis for our trading and non-trading activities as at March 31, 2008. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.
Level 1 Level 2 Level 3 Total
---------------------------------------------------------------------------
Net Derivatives
Trading Derivatives 148 7 (34) 121
Non-Trading Derivatives - (59) - (59)
----------------------------------------
Total Net Derivatives 148 (52) (34) 62
----------------------------------------
----------------------------------------A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the three months ended March 31, 2008 is provided below:
Level 3
---------------------------------------------------------------------------
Fair Value at January 1, 2008 (7)
Realized and unrealized gains (losses) (5)
Purchases, issuances and settlements (2)
Transfers in and/or out of Level 3 (20)
---------
Fair Value at March 31, 2008 (34)
---------
---------
Unsettled gains (losses) relating to instruments
still held as of March 31, 2008 (23)
---------
---------Transfers in and/or out represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. 11. RISK MANAGEMENT (a) Market Risk We invest in significant capital projects, purchase and sell commodities, issue short and long-term debt including amounts in foreign currencies and invest in foreign operations. These activities expose us to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage exposures to market risk that result from these activities. The following market risk discussion relates primarily to commodity price risk and foreign exchange risk related to our financial instruments. Our exposure to interest rate risk is immaterial. Commodity price risk We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in world crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, such prices also may affect the value of our oil and gas properties and our level of spending for exploration and development. The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. From time to time, we actively manage these risks by using derivative contracts such as commodity put options. Our energy marketing group markets and trades crude oil, natural gas, NGLs, ethanol and power through physical purchase and sales contracts, as well as financial commodity contracts. These activities expose us to commodity price risk, as well as foreign currency risk and volatility within these markets. Our energy marketing group actively manages this risk by utilizing energy and currency derivatives. We typically take advantage of location, time and quality spreads using physical and financial contracts. The marketing group also tries to take advantage of volatility within commodity markets and can establish net open commodity positions to take advantage of existing market conditions. Volatility within our various markets can vary and change over time. While this volatility gives us opportunities, it can also cause our results to vary significantly between periods. We attempt to manage associated risk and take on positions based on solid market intelligence; however, it is possible that we could incur financial loss. Open positions exist when not all contracted purchases and sales terms have been matched. These net open positions allow us to generate income, but also expose us to risk of loss due to fluctuating market prices (market risk sensitivities in our portfolio). We manage the level of market risk through daily monitoring of our energy-trading activities relative to: - prescribed limits for Value-at-Risk (VaR); - nominal size of commodity positions; - stop loss limits; and - stress testing. VaR is a statistical estimate assuming normal market conditions exist. Our VaR calculation estimates the maximum probable loss, given a 95% confidence level that we would incur if we were to unwind our outstanding positions over a two-day period. We estimate VaR primarily by using the Variance-Covariance method based on historical commodity price volatility, correlation inputs where available and by historical simulation in other situations. Our estimate is based upon the following key assumptions: - changes in commodity prices follow a statistical pattern of distribution; - price volatility remains stable; and - price correlation relationships remain stable. If a severe market shock occurred, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We also use stress testing using extreme market movements which complements our VaR estimates. It is used to quantify potential unexpected losses from low probability market movements. Our VaR analysis incorporates our derivative positions, non-derivative transportation and storage contracts and assets, as well as commodity trading inventories. Our quarter end, high, low, and average VaR amounts for the three months ended March 31 are as follows:
Three months
ended March 31
2008 2007
---------------------------------------------------------------------------
Value-at-Risk
Quarter End 35 33
High 40 35
Low 21 24
Average 30 28
---------------------Foreign currency risk Foreign exchange risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including: - sales of crude oil, natural gas and certain chemicals products; - capital spending and expenses for our oil and gas, Syncrude and chemicals operations; - commodity derivative contracts used primarily by our energy marketing group; and - short-term and long-term borrowings. In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Net revenue from our foreign operations and our US-dollar borrowings are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. At March 31, 2008, we had US$4,413 million of long-term debt issued in US dollars and a one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $45 million, before income tax. In our energy marketing group, the majority of the financial commodity contracts are denominated in US dollars. We enter into US-dollar forward contracts and swaps to manage this exposure. We also have immaterial exposures to currencies other than the US dollar. A portion of our United Kingdom operating expenses, capital spending and future asset retirement obligations are denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. (b) Credit Risk Credit risk affects both our trading and non-trading activities and is the risk of loss if counterparties do not fulfill their contractual obligations. The majority of our accounts receivable are with counterparties in the energy industry and are subject to normal industry credit risk. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We assess the financial strength of our counterparties, including those involved in marketing and other commodity arrangements, and we limit the total exposure to individual counterparties. As well, a number of our contracts contain provisions that allow us to demand the posting of collateral in the event of a downgrade to a non-investment grade credit rating occurs. Credit risk, including credit concentrations, is routinely reported to our management, including the Risk Management Committee. We also use standard agreements that allow for the netting of exposures associated with a single counterparty. We believe this minimizes our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance. At March 31, 2008: - over 97% of our credit exposures were investment grade; and - only one counterparty individually made up more than 10% of our credit exposure. This counterparty was investment grade. Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as accounts receivable, as well as the fair value of derivative financial assets. There are no significant amounts past due or impaired at the balance sheet date. Collateral received from customers at March 31, 2008 includes $17 million of cash and $581 million of letters of credit related to our trading activities and the cash received is included in our accounts payable and accrued liabilities. (c) Liquidity Risk Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to engage in our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At March 31, 2008, we had unsecured term credit facilities of US$3 billion available until 2012. At March 31, 2008, no amounts were drawn on these facilities, however, $296 million of the facilities were used to support outstanding letters of credit. We also had $666 million of undrawn, uncommitted, unsecured credit facilities, of which $44 million was supporting letters of credit at March 31, 2008. The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at March 31, 2008:
less greater
than than
Total 1 Year 1-3 Years 4-5 Years 5 Years
---------------------------------------------------------------------------
Long-Term Debt 4,660 125 218 - 4,317
Interest on
Long-Term Debt (1) 6,593 219 548 548 5,278
--------------------------------------------------
Total 11,253 344 766 548 9,595
--------------------------------------------------
--------------------------------------------------
(1)Excludes interest on term credit facilities of US$3 billion and Canexus
LP term credit facilities of $350 million as the amounts drawn on the
facilities fluctuate. As a result, we are unable to provide a reasonable
estimate of the interest.The following table details contractual maturities for our derivative financial liabilities. The balance sheet amounts for derivative financial liabilities included below are not materially different from the contractual amounts due on maturity.
less greater
than than
Total 1 Year 1-3 Years 4-5 Years 5 Years
---------------------------------------------------------------------------
Trading Derivatives 768 543 206 19 -
Non-Trading Derivatives 89 38 51 - -
--------------------------------------------------
Total 857 581 257 19 -
--------------------------------------------------
--------------------------------------------------The commercial agreements our energy marketing group enters into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event, such as a drop in credit ratings, occurs. Based on contracts in place and commodity prices at March 31, 2008, we could be required to post collateral of up to $1.7 billion if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral merely secures the payment of such amounts. At March 31, 2008, collateral posted to our counterparties includes $36 million of cash and $200 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Letters of credit issued cannot be drawn on unless there has been default, which would have to be proven to the bank in order for them to release the funds. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained. Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $75 million (December 31, 2007 - $203 million), which have been included in restricted cash. 12. SHAREHOLDERS' EQUITY Dividends Dividends per common share for the three months ended March 31, 2008 were $0.025 (2007 - $0.025). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes. 13. 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
Ended March 31
(millions of shares) 2008 2007
---------------------------------------------------------------------------
Weighted-average number of common
shares outstanding 528.9 526.0
Shares issuable pursuant to tandem options 22.5 28.4
Shares notionally purchased from proceeds
of tandem options (14.2) (15.8)
----------------------
Weighted-average number of diluted
common shares outstanding 537.2 538.6
----------------------
----------------------In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2008, we excluded 4,103,560 tandem options, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2007, 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 tandem options were the only potential dilutive instruments.
14. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months
Ended March 31
2008 2007
---------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 364 334
Stock-Based Compensation (59) 44
Future Income Taxes 77 35
Change in Fair Value of Crude Oil Put Options - 16
Net Income Attributable to Non-Controlling Interests 1 3
Other - 3
----------------------
Total 383 435
----------------------
----------------------
(b) Changes in non-cash working capital
Three Months
Ended March 31
2008 2007
---------------------------------------------------------------------------
Accounts Receivable (446) 75
Inventories and Supplies (78) 65
Other Current Assets (10) (4)
Accounts Payable and Accrued Liabilities 683 (58)
Accrued Interest Payable 13 (18)
----------------------
Total 162 60
----------------------
----------------------
Relating to:
Operating Activities 140 32
Investing Activities 22 28
----------------------
Total 162 60
----------------------
----------------------
(c) Other cash flow information
Three Months
Ended March 31
2008 2007
---------------------------------------------------------------------------
Interest Paid 66 101
Income Taxes Paid 85 57
----------------------Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $10 million for the three months ended March 31, 2008 (2007 - $10 million). 15. MARKETING AND OTHER INCOME
Three Months
Ended March 31
2008 2007
---------------------------------------------------------------------------
Marketing Revenue, Net 211 247
Change in Fair Value of Crude Oil Put Options - (16)
Interest 10 9
Foreign Exchange Gains (Losses) 5 (5)
Other (4) 13
----------------------
Total 222 248
----------------------
----------------------16. COMMITMENTS, CONTINGENCIES AND GUARANTEES As described in Note 15 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. 17. OPERATING SEGMENTS AND RELATED INFORMATION Nexen is involved in activities relating to Oil and Gas, Energy Marketing, Syncrude and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.
Three months ended March 31, 2008
(Cdn$ millions) Oil and Gas
---------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------
Net Sales 276 147 181 939 46
Marketing and Other 4 - 1 1 -
----------------------------------------------------
Total Revenues 280 147 182 940 46
Less: Expenses
Operating 45 42 24 57 3
Depreciation,
Depletion,
Amortization
and Impairment 34 47 74 170 4
Transportation
and Other 2 5 1 - -
General and
Administrative (4) (2) 1 6 (1) 1
Exploration - 4 6 7 15(5)
Interest - - - - -
----------------------------------------------------
Income (Loss)
before Income Taxes 201 48 71 707 23
Less: Provision for
(Recovery of)
Income Taxes 70 14 | |||