Nexen Inc.

Nexen Inc.

December 08, 2009 22:30 ET

Nexen Provides Long Lake Oil Sands Project Update, Announces Owowo Discovery, Offshore West Africa and 2010 Budget

CALGARY, ALBERTA--(Marketwire - Dec. 8, 2009) - Nexen continues to see positive results at Long Lake following the successful completion of the turnaround program in September. As we move into 2010, our priorities include the ramp up of Long Lake, sanctioning our discoveries in the North Sea, the continued improvement of our Horn River shale gas returns, the development of our offshore Usan project and ongoing exploration in our core areas.

Long Lake Project Update

At Long Lake, we have achieved a number of major milestones over the past year. Our gasification process is working as designed, creating a low cost fuel source which reduces our need to purchase natural gas for operations. Once the project is fully ramped up, it generates a significant margin advantage over our peers and we maintain this advantage even at current gas prices.

The upgrader is fully operational. We are approaching design yields and we have successfully produced over 1.5 million barrels of the highest quality synthetic crude in North America. Upgrader run times are increasing and in November, improved reliability allowed us to process 95% of our bitumen production.

Now that all components of the upgrader are operating as planned, we are focused on maximizing bitumen throughput. We will achieve this by increasing production volumes from our reservoir and by purchasing bitumen from third-parties to enhance returns.

The reservoir is responding to consistent steaming. Following a turnaround completed in September, the reliability of our water treating systems has improved substantially and currently, steam injection rates are at an all-time high of approximately 100,000 bbls/d. We are injecting steam into over 70 well pairs with 50 on production and the remainder circulating steam in advance of becoming producers. This is the highest number of wells that have received consistent steam to date. Prior to the turnaround, steam limitations only allowed us to inject steam consistently into approximately 35 well pairs.

Bitumen production levels are responding to the increased steam volumes and gross production is averaging approximately 17,000 bbls/d. As we start to circulate steam in more wells, our all-in steam-to-oil ratio (SOR) will remain high and is currently approximately 6 with about 20 wells receiving steam but not yet producing bitumen. The SOR of our producing wells is approximately 4.5 and trending down. With the ongoing installation of electric submersible pumps (ESPs), we are seeing improvements in our SORs. We continue to expect a long term SOR of 3 over the life of the project.

In addition to the continued installation of ESPs, our capital investment program in the coming year includes the drilling of two sustaining well pads in accordance with our full field resource development plan. These pads will be available to come on stream starting in 2012.

"We are still in the SAGD ramp up phase and are pleased with post-turnaround performance," said Marvin Romanow, Nexen's President and Chief Executive Officer. "Steaming reliability has improved and this is leading to higher bitumen production. We are confident that we will ramp up to full rates and demonstrate the significant value this project will deliver to our shareholders."

Owowo Discovery, Offshore West Africa

Earlier this year, we participated in the drilling of an exploration well in the southern portion of Oil Prospecting License (OPL) 223, offshore West Africa, which we are pleased to announce was successful.

The Owowo South B-1 well was drilled in a water depth of 670 metres and is located 20 kilometres northeast of the Usan field, currently under development. The well reached a total depth of 2,227 metres and discovered several oil bearing reservoirs containing light oil according to logs and other analysis.

Under the production sharing contract governing OPL 223, the Nigerian National Petroleum Corporation (NNPC) is concessionaire of the license, which is operated by Total Exploration & Production Nigeria Ltd. Nexen has an 18% interest in the discovery.

"We continue to have success with our exploration program offshore West Africa," said Romanow. "This discovery makes us more optimistic about our other exploration prospects."

2010 Budget

Our strategies are focused on oil sands, shale gas and conventional development and exploration in select basins. In 2010, we plan to advance these strategies by investing $2.5 billion and growing production after royalties by approximately 4 to 6% assuming the midpoint of our guidance.

Highlights of our 2010 budget are as follows:

- Production after royalties has grown over the last three years at an annual compound rate of over 10% with further growth of approximately 4 to 6% expected in 2010 assuming the midpoint of our guidance. At the high end of our guidance range, volumes would grow over 15%

- Capital investment plans of $2.5 billion solidify growth beyond 2010 as we develop Usan, Golden Eagle, Long Lake and Horn River shale gas

- Production volumes expected to range from 200,000 to 250,000 boe/d (230,000 to 280,000 boe/d before royalties)

- Capital program funded with cash flow assuming WTI averages around US$70/bbl; free cash flow of approximately $600 million at current strip prices

- 15 exploration and appraisal wells planned, testing approximately 600 million boes of net unrisked resource potential

Investing in Our Strategies
Estimated 2010
Capital Investment Profile ($Cdn millions)
Conventional development and exploration 1,800
Oil sands 400
Shale gas 200
Corporate, chemicals and other 100
Total Capital Investment 2,500

Assuming WTI averages about US$70/bbl and NYMEX gas averages US$5.50/mmbtu, we expect our cash flow to fund our 2010 capital investment program at a US/Cdn dollar exchange rate of 0.90. At current strip prices, we expect next year's cash flow to exceed capital by approximately $600 million. Our production is 85% weighted to oil.

We have purchased crude oil put options on 60,000 bbls/d of our 2010 production at a strike price of WTI US$50/bbl. Half of these puts settle monthly, with the remainder settling annually. We continue to look for opportunities to purchase more.

Changes in commodity prices and exchange rates impact our after-tax cash
flow as follows:

Impact on After-
Tax Cash Flow
2010 Sensitivities ($Cdn millions)
US$1.00 change in crude oil prices above US$50 50
US$1.00 change in crude oil prices below US$50 (1) 35
US$0.50 change in natural gas prices 30
US$0.01 change in exchange rate 35
(1) Includes the impact of put options purchased on 60,000 bbls/d of
production at WTI US$50/bbl.

Production-Volumes Growing from New Core Assets

Over the last three years, our net production has grown at a robust annual compound rate of over 10%. This growth is expected to continue in 2010 as we ramp up Ettrick, Longhorn and Long Lake. Our capital program in 2010 advances our future growth as we move forward with the development of several major identified projects including Long Lake, Usan, Golden Eagle and Horn River shale gas. Our growth is being fueled by new, low royalty projects which more than offset high royalty production declines in Yemen.

We expect our annual 2010 production to range from 230,000 to 280,000 boe/d before royalties.

2010 Estimated Annual Production
Before Royalties After Royalties
(mboe/d) (mboe/d)
North Sea 100-130 100-130
Yemen 32-37 19-23
Canada (1) 28-34 19-25
Long Lake Bitumen (2) 20-30 18-28
Syncrude 19-24 18-23
US Gulf of Mexico 20-28 17-25
Other International approximately 2 1-2
Total 230-280 200-250
(1) Excludes oil sands.
(2) Long Lake production reflects bitumen rather than synthetic crude.

In the North Sea, we expect seven to ten days of downtime at Buzzard in the second quarter for the installation of the topsides relating to the fourth platform. This platform will allow us to handle higher levels of hydrogen sulphide over the life of the field and maintain peak production rates until 2014. Based on our production experience to date, we anticipate that start up of the new platform will not be required until 2011. If advanced to 2010, downtime associated with the start up could reduce annual volumes by 10,000 to 15,000 boe/d. This possibility is reflected in our guidance range.

Elsewhere in the North Sea, we anticipate drilling an additional development well at Telford to allow for higher production volumes from our recent Telford success. In the event these activities do not occur in 2010, annual volumes would be reduced by about 5,000 boe/d.

At Long Lake, we successfully completed our turnaround program in September. Our bitumen volumes are increasing and we are moving up the ramp up curve. Our SAGD and upgrading processes are highly integrated. This integration ultimately generates our significant margin advantage while supporting the environmentally responsible water management practices we have implemented. As a result, the pace at which we move up the ramp up curve comes with a degree of variability. This is reflected in our guidance range. While we expect periods of downtime at Long Lake as the project continues to ramp up, we anticipate continuing improvements in operational performance as we move towards full capacity.

In Yemen, production volumes are declining at rates similar to previous years.

Syncrude is planning one coker turnaround in 2010 for routine maintenance.

The timing of potential activities in the North Sea and the ramp up of Long Lake are the biggest contributors to the range of our guidance.

Conventional Development and Exploration-Investing In Our Future Growth

We plan to invest approximately $1.8 billion on conventional development and exploration with two-thirds relating to the development of existing assets and discoveries, and the remainder relating to exploration in our three core basins: the North Sea, offshore West Africa and the deep-water Gulf of Mexico. Our exploration plans include the potential drilling of 15 exploration and appraisal wells targeting a net unrisked resource potential of approximately 600 million boes.

Conventional Development and
Capital Investment Profile
($Cdn Millions) North Sea W. Africa US Other Total
Major Development 75 575 50 - 700
Core Asset Development 425 - 50 50 525
Exploration and Appraisal 350 50 125 50 575
Total 850 625 225 100 1,800

North Sea Development

At Buzzard, the topsides for the fourth platform are scheduled for installation in the second quarter and start up is scheduled for 2011. This platform contains production sweetening facilities designed to handle higher levels of hydrogen sulphide which will allow us to maintain plateau until at least 2014. We also plan to drill five production wells and one injection well.

At Scott/Telford, we plan to follow up our 2009 development success with additional drilling and see further upside in the area with opportunities for quick tiebacks. Additional development drilling is planned at Ettrick along with appraisal drilling at Blackbird, which would be a tie-back to Ettrick.

Elsewhere in the UK North Sea, we are progressing the sanctioning of the Golden Eagle area development. As previously announced, estimates of gross contingent recoverable resource here range between 150 and 275 million boe. We expect development will support standalone facilities due to its size and be economic with oil prices as low as US$40/bbl.

"The Golden Eagle area is the largest discovery in the UK North Sea in the last 10 years after Buzzard," commented Romanow. "The development of Golden Eagle allows us to maintain or grow our North Sea production for the next five to ten years."

Offshore West Africa Development

Development of the Usan field on block OML 138, offshore Nigeria, is progressing well. The field development plan includes a floating production and storage offloading (FPSO) vessel with an oil storage capacity of two million barrels. In 2010, we expect to complete fabrication of the FPSO hull and most of the topsides. In addition, we will continue development drilling and well completion activities. The Usan field is expected to come on-stream in 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us). Nexen has a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.

Exploration and Appraisal

Exploration and Appraisal Profile # of wells
North Sea
UK Appraisal Wells 6
UK Exploration Wells 3
Norway Exploration Wells 1
Total North Sea 10
Gulf of Mexico
Exploration Wells 4
Exploration Wells 1
Total 15

On the exploration front, we plan to drill a number of exciting opportunities in the North Sea including the North Uist prospect, west of the Shetland Islands, and the Brand prospect, our first well in Norway. Both of these prospects have higher target sizes than our typical North Sea targets. In addition, we plan to drill up to eight other exploration and appraisal wells. This includes Bluebell, a possible southern extension of the Buzzard field, and the Deacon and Bugle exploration wells, which take advantage of our regional success with stratigraphic traps.

In the Gulf of Mexico, we are currently drilling an appraisal well at Knotty Head and results are expected in the second quarter. The well is being drilled by our first contracted deep-water rig, the Ensco 8501. A second deep-water rig, the Ensco 8502, is scheduled to arrive in mid-2010. Access to these two deep-water rigs allows us to move forward with our exploration program and we expect to drill up to four exploration wells in 2010. High impact prospects that could be drilled include Kakuna, Angel Fire and Solitude, and a non-operated prospect, Catalina.

In Colombia, we plan to participate in the El Guadual exploration well and offshore West Africa, further exploration drilling may take place as early as 2010 following the recent success at Owowo.

"We are adding value by advancing our discoveries and building on our drilling success in the UK," said Romanow. "We have added experienced people to our talent pool and access to new deep-water rigs in the Gulf of Mexico will allow us to keep progressing our large inventory of exciting prospects."

Oil Sands-Keeping the Upgrader Full at Long Lake is a Priority

We plan to invest $400 million in oil sands in 2010 which includes $100 million at Syncrude. In the coming year, our capital program at Long Lake Phase 1 will focus on the drilling of sustaining well pads and the continued installation of ESPs in our SAGD wells.

With respect to future phases of Long Lake, we plan to continue engineering work on Phase 2 with timing of sanctioning dependent on multiple factors including the ramp up of Phase 1, receiving clarity on proposed climate change regulations, finalizing cost estimates and seeing more confidence in a sustained economic recovery.

Horn River Shale Gas-Continued Focus on Improving Returns

We have approximately 88,000 acres in the Dilly Creek area of the Horn River basin in northeast British Columbia with a 100% working interest. We estimate our lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of contingent recoverable resource which could double our existing company-wide total proved reserves.

With our recent drilling and completion program, we realized substantial cost savings and productivity improvements and are producing at rates in line with regional producers. We took advantage of improved equipment utilization, drilled longer wells, initiated more fracs per well and maintained an industry-leading frac pace of 26 fracs in 15 days while achieving a 100% success rate on our frac program.

In 2010, we plan to invest about $200 million on the drilling and completion of an eight-well pad and on processing facilities. Compared to our earlier programs, this pad will have longer horizontal wells with more fracs and higher frac densities (18 fracs per well). We expect to achieve shale gas volumes from this program of approximately 50 mmcf/d in early 2011. This program sets up a potential capital investment plan consisting of an 18-well pad which could commence drilling in 2010.

"Larger programs, increased well productivities and higher recovery factors result in lower unit costs and are the catalysts to driving higher Horn River returns," said Romanow. "I am pleased with our progress and our success is setting industry benchmarks."

Ongoing Strategic Review of our Portfolio

We regularly review the assets in our portfolio to ensure that they are aligned with our strategies and can compete for investment funding against other opportunities. We have identified a number of non-core assets for possible disposal, including parts of our marketing business, our heavy oil assets in Western Canada and our interest in the Canexus chemicals business. We expect that the disposition of non-core assets could generate over $1 billion in the next 12 to 24 months with timing dependent on market conditions.

"Assets that are no longer aligned with our main areas of focus will be monetized to maximize value," said Romanow. "We have an excellent portfolio of opportunities with significant captured resource and will focus on these."

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 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 on our previously announced contingent recoverable shale gas and Golden Eagle area resource were provided in our press releases dated April 22, 2008 and September 3, 2009 respectively. Information with respect to forward-looking statements and cautionary notes is set out below.

Conference Call

Marvin Romanow, President and CEO, and Kevin Reinhart, Senior Vice-President and CFO will host a conference call to review our 2010 budget.

Date: December 9, 2009

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:

416-695-6616 (Toronto)

800-766-6630 (North American toll-free)

800-4222-8835 (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 8082845 followed by the pound sign. A live and on demand webcast of the conference call will be available at

Capital Investment Profile
Estimated 2010
Capital Investment Profile ($Cdn millions) %
Core Asset Development 825 33
Major Development 700 28
Early Stage Development 300 12
Total Development 1,825 73
Exploration and Appraisal 575 23
Total Oil and Gas Capital 2,400 96
Corporate, Chemicals and Other 100 4
Total Capital Investment 2,500 100

Core Asset Development Estimated 2010
Capital Investment Profile ($Cdn millions)
North Sea 425
Gulf of Mexico 50
Other 50
Total Conventional Core Asset Development 525
Long Lake and Syncrude 300
Core Asset Development 825

Major Development Estimated 2010
Capital Investment Profile ($Cdn millions)
Offshore West Africa - Usan 575
Golden Eagle Area 50
Other 75
Major Development 700

Early Stage Development Estimated 2010
Capital Investment Profile ($Cdn millions)
Horn River Shale Gas 200
Long Lake - Future Phases 100
Core Asset Development 300

Exploration and Appraisal Estimated 2010
Capital Investment Profile ($Cdn millions)
Offshore Exploration and Appraisal
North Sea 350
Gulf of Mexico 125
West Africa 50
Other 50
Exploration and Appraisal 575

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) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook", "forecast" or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future 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, availability of committed credit facilities, 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 current and long-term assets, 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, come on stream, or reach expected operating capacity and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

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, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design modifications to facilities; 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 2008 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", "recoverable resources" and "recoverable contingent 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 an SEC registrant and a voluntary Form 10-K (and related forms) filer. Therefore, our reserves estimates and securities regulatory disclosures follow SEC requirements. In Canada, National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities (NI 51-101) prescribes that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. Nexen reserves disclosures are made in reliance upon exemptions granted to Nexen by Canadian securities regulators from certain requirements of NI 51-101 which permits us to:

- prepare our reserves estimates and related disclosures in accordance with SEC disclosure requirements, generally accepted industry practices in the US and the standards of the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) modified to reflect SEC requirements;

- substitute those SEC disclosures for much of the annual disclosure required by NI 51-101; and

- rely upon internally-generated reserves estimates and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, included in the Supplementary Financial Information, without the requirement to have those estimates evaluated or audited by independent qualified reserves evaluators.

As a result of these exemptions, Nexen's disclosures may differ from other Canadian companies and Canadian investors should note the following fundamental differences in reserves estimates and related disclosures contained herein:

- SEC registrants apply SEC reserves definitions and prepare their proved reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;

- the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using year-end constant prices and costs only whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices;

- the SEC mandates disclosure of proved and proved developed reserves by geographic region only whereas NI 51-101 requires disclosure of more reserve categories and product types;

- the SEC does not prescribe the nature of the information required in connection with proved undeveloped reserves and future development costs whereas NI 51-101 requires certain detailed information regarding proved undeveloped reserves, related development plans and future development costs;

- the SEC does not require disclosure of finding and development (F&D) costs per boe of proved reserves additions whereas NI 51-101 requires that various F&D costs per boe be disclosed. NI 51-101 requires that F&D costs be calculated by dividing the aggregate of exploration and development costs incurred in the current year and the change in estimated future development costs relating to proved reserves by the additions to proved reserves in the current year. However, this will generally not reflect full cycle finding and development costs related to reserve additions for the year;

- the SEC leaves the engagement of independent qualified reserves evaluators to the discretion of a company's board of directors whereas NI 51-101 requires issuers to engage such evaluators and to file their reports;

- the SEC does not consider the upgrading component of our integrated oil sands project at Long Lake as an oil and gas activity, and therefore permits recognition of bitumen reserves only. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits recognition of synthetic reserves. At year end, we have recognized 285 million barrels before royalties of proved bitumen reserves (282 million barrels after royalties) under SEC requirements, whereas under NI 51-101 we would have recognized 233 million barrels before royalties of proved synthetic reserves (231 million barrels after royalties);

- the SEC considers our Syncrude operation as a mining activity rather than an oil and gas activity, and therefore does not permit related reserves to be included with oil and gas reserves. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits them to be included with oil and gas reserves. We have provided a separate table showing our share of the Syncrude proved reserves as well as the additional disclosures relating to mining activities required by SEC requirements; and

- any reserves data in this document reflects our estimates of reserves. While we obtain an independent assessment of a portion of our reserves estimates, no independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this Form 10-K.

The foregoing is a general description of the principal differences only. Please note that the differences between SEC requirements and NI 51-101 may be material.

NI 51-101 requires that we make the following disclosures:

- we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; and

- because reserves data are based on judgments regarding future events actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery.


Nexen'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, a lower level of delineation, the absence of regulatory approvals, detailed design estimates and near-term development plans, 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. We disclose additional information regarding resource estimates in accordance with NI 51-101. These disclosures can be found on our website and on SEDAR.

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.

Contact Information

  • Michael J. Harris, CA
    Vice President, Investor Relations
    (403) 699-4688
    Lavonne Zdunich, CA
    Manager, Investor Relations
    (403) 699-5821
    Tim Chatten, P.Eng
    Analyst, Investor Relations
    (403) 699-4244
    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7