Nexen Inc.

Nexen Inc.

November 15, 2010 22:06 ET

Nexen Provides 2011 Production and Capital Investment Guidance, Announces Sale of North Dakota/Montana Marketing Business and Announces Resource Estimates for its Oil Sands and Shale Gas Assets

CALGARY, ALBERTA--(Marketwire - Nov. 15, 2010) - Our growth strategies are centered around oil sands, shale gas and conventional development and exploration in select basins. As we move into 2011, we will continue to concentrate on execution excellence. Our near-term priorities comprise the continued ramp up of Long Lake, completing the development of our Usan discovery with first oil in 2012, sanctioning discoveries, advancing the development of our Horn River shale gas lands, securing a contract extension in Yemen and continuing our exciting global exploration program. Our capital investment program for 2011 ranges from $2.4 to $2.7 billion. We expect to grow production after royalties by approximately 4% assuming the midpoint of our guidance range and 7% adjusting for the sale of our heavy oil properties in mid-2010 which generated $1 billion of proceeds.

2011 Production Guidance
2011 Estimated Annual Production
Before Royalties After Royalties
(mboe/d) (mboe/d)
North Sea 110-130 110-130
Yemen 28-35 16-20
Canada 18-26 16-23
Long Lake Bitumen 25-29 22-26
Syncrude 20-24 18-22
US Gulf of Mexico 20-28 17-24
Other International 2-3 2-3
Total 230-270 210-240

As we close out this year, production is expected to average 240,000 and 250,000 boe/d for 2010, well within our original annual production guidance range of 230,000 to 280,000 boe/d even with the successful sale of 15,000 boe/d of heavy oil assets mid-year and the unexpected eight week shutdown of our Scott platform in the North Sea for a valve failure on the Forties pipeline. These two events were not contemplated in our original guidance range.

For 2011, we expect our production will range between 230,000 and 270,000 boe/d, before royalties. The range is driven by the pace of ramp up at Long Lake, run-times at Buzzard and Scott/Telford in the North Sea, and the timing of new volumes from our North Sea tieback opportunities and from our Horn River shale gas program.

At Long Lake, we expect annual bitumen production volumes in 2011 will average between 38,000 and 45,000 bbls/d (25,000 to 29,000, net to us) as compared to approximately 25,000 bbls/d in 2010. In 2010, our mature wells continued to grow as we provided them with more steam. We brought on stream 26 new wells and they are starting to contribute as well. We installed electric submersible pumps in all wells that could benefit from them and started optimization work on various wells. These activities had us on a steady ramp towards the lower end of our guidance range until upgrader disruptions in the late summer set us back several months. In 2011, the producing wells will continue to grow, we expect to bring on the remaining 14 wells and we will continue to pursue optimization opportunities. In addition, we expect to drill two additional well pads in 2011 that we plan to have on stream in 2012. As consistent steam is critical to driving bitumen production, we are progressing engineering on investments to expand our steam capacity and to provide greater independence between the SAGD and upgrader operations while retaining the benefits of the integrated process. We expect these various initiatives will allow us to fill the upgrader. In October, we produced about 29,000 bbls/d and achieved cash flow breakeven at US$80 WTI. With operating costs largely fixed, we are on track to generate net annual cash flows of $550 to $800 million at US$70 to US$90 WTI at full design rates.

"At the mid-point of our guidance ranges, production volumes after royalties would grow by as much as 7%. This continues the robust growth of about 7% on a compound annual basis we have realized over the prior five years, after considering the sale of our heavy oil properties," said Marvin Romanow, President and CEO. "This 2011 growth is the first step to our delivery of about 70,000 boe/d of new production over the next 24 months as we bring on Usan, UK tiebacks, shale gas and ramp up Long Lake. Beyond this, we expect further upside from a successful Yemen contract extension and from the development of our existing discoveries."

2011 Capital Investment Program
Estimated 2011 Capital Investment
($Cdn millions)
Conventional Development and Exploration 1,500-1,600
North Sea 750
West Africa 500
Gulf of Mexico 250
Other 50
Oil Sands 550-600
Long Lake, Kinosis & Other SAGD 425
Syncrude 150
Shale Gas 300-350
Total Oil and Gas Capital 2,350-2,600
Corporate, Chemicals and Other 50-100
Total Estimated Capital Investment 2,400-2,700

In 2010, we expect our capital investment to be approximately $2.9 billion and expect proved reserve additions to range from 50 to over 100 million boes. The range primarily reflects the timing of reserve recognition for our Golden Eagle discovery. Our proved reserve bookings over the last five years have more than replaced production.

In 2011, we plan to invest between $2.4 and $2.7 billion to advance our strategies and expect to generate between $2.1 and $2.8 billion of cash flow assuming WTI ranges between $75 and $90.

Conventional Development and Exploration

Our capital investment plans for our conventional assets are focused on developing our existing discoveries and exploring our extensive high quality land portfolio. This will allow us to grow and generate long term value alongside our oil sands and shale gas assets.

In the UK North Sea, we plan to sanction the development of our discoveries in the Golden Eagle area. Our current estimate of gross contingent recoverable resource here is 150 million boe or more. We also plan to advance some of our infrastructure tieback projects towards first production including Telford, Blackbird, Rochelle and West Rochelle.

Offshore West Africa, the Usan development is moving closer to first oil in 2012. With the floating production, storage and offloading vessel (FPSO) nearing completion, our capital investment here will be focused on final fabrication and installation of offshore subsea facilities and ongoing development drilling. Further exploration to follow up our Owowo success is under consideration.

In the Gulf of Mexico, we are moving ahead with plans to recommence our exploration program now that the moratorium has been lifted. At Knotty Head, we expect an integrated project team will be in place next year to start work on a joint development plan with Hess to move the Pony and Knotty Head discoveries towards sanctioning.

Exploration and Appraisal

We have an exciting exploration and appraisal program planned for 2011 and anticipate spending approximately 25% of our capital investment program ($600 to $650 million) on drilling 22 prospects. Success from this program will generate the next wave of new growth opportunities to follow the five major discoveries we already have in the development queue.

Exploration and Appraisal Profile # of wells
Gulf of Mexico
Exploration Wells 3
Appraisal Wells 3
North Sea
UK Exploration Wells 4
UK Appraisal Wells 2
Norway Exploration Wells 2
Canadian Tight Oil 3
Colombian Shale Gas 4
Colombian Exploration Wells 1
Total 22

In the Gulf of Mexico, our drilling program includes six exploration and appraisal wells. We have three exciting wells in the deepwater planned at Kakuna, Angel Fire and Cypress. At Appomattox, where our current estimate of gross contingent resource exceeds 250 million boe, we expect to commence appraisal activities early in the year.

Highlights of our North Sea exploration program include the North Uist prospect, west of the Shetland Islands, and the Votna prospect, our second well in Norway. These prospects have higher target sizes than our typical North Sea targets.

"We are moving a number of our large exploration successes to the development phase with Usan on deck to start delivering step-change cash flow in 2012," said Romanow. "After this, we look forward to bringing Golden Eagle, Knotty Head, Appomattox and Owowo on-stream."

Oil Sands

In the oil sands, our capital investment plans are focused on filling our Long Lake upgrader and starting to develop some of the vast resource we hold.

We plan to drill pads 12 and 13, with first production targeted for 2012. In addition, we plan to continue investing in opportunities to improve the robustness and reliability of our plants and infrastructure. As a result, we are progressing the engineering on two more once-through steam generators (OTSGs) that will add 10 to 15% to our existing steam capacity. We are also planning projects that will increase the operating independence between our SAGD facilities and the upgrader while maintaining the benefits of integration. All capital projects are subject to normal partner approval processes.

"The two new pads represent an acceleration of future project capital and we expect the incremental capital of adding additional steam capacity and more independence between our SAGD facilities and the upgrader to add less than 5 percent to our total Long Lake investment," said Romanow.

Beyond Long Lake, we are investing capital to bring more of our substantial oil sands resource closer to development. At Kinosis, we plan to be sanction-ready in 2012 on the first of our two 40,000 bbls/d SAGD projects and we are also moving forward with our non-operated SAGD project at Hangingstone. At Syncrude, we plan to invest about $150 million in 2011 primarily on mine replacement activity and tailings pond management.

Shale Gas

Our capital investment plans on our Horn River acreage are focused on the continued successful execution of our drilling and completion programs.

We plan to finish drilling our nine-well pad this winter with frac and completion activities planned for next summer. We are progressing plans to commence drilling an 18-well pad in the second half of 2011. First shale gas production from the nine-well pad is expected in the fourth quarter of 2011 with production from the 18-well pad expected in late 2012.

Disposition of North Dakota/Montana Crude Oil Marketing Business

We have recently entered into an agreement to sell our oil lease gathering, pipelines and storage assets in North Dakota and Montana for approximately $210 million. We expect to report a gain on the sale of between $115 million and $130 million. The sale is expected to close by the end of this year.

"This brings the total proceeds from our non-core asset sales to over $1.2 billion," said Romanow. "We now expect to generate well over $1.5 billion from all asset sales, once we complete our disposition program which includes the sale of Canexus over the next twelve months. The proceeds will be used to develop the success we are having throughout our portfolio."

Oil Sands and Shale Gas Contingent Resource Estimates

We have developed estimates of contingent resource for our Alberta oil sands interests which are comprised of our 65% interest in Long Lake, Kinosis, Leismer and Cottonwood, our 7.23% ownership in Syncrude, our 25% interest in Hangingstone and our variable interests in other joint venture oil sands projects. These estimates cover our approximate 265,000 net acre land position.

With respect to the oil sands, our contingent resource estimates range from approximately 3 to 6 billion barrels of bitumen with a best estimate of 4 billion barrels. In addition, we have 1.6 billion barrels of total proved plus probable synthetic crude oil reserves (which equates to 1.9 billion barrels of bitumen before upgrading). McDaniel & Associates have provided an audit opinion that our aggregate oil sands estimates are reasonable.

In addition, we now have substantial acreage of over 300,000 acres in the Horn River, Cordova and Liard basins in NE British Columbia, which we own with a 100% working interest.

We estimate that our Dilly Creek lands in the Horn River and our Cordova acreage contain between 4 and 15 tcf of contingent resource and our Liard acreage contains between 5 and 23 tcf of unrisked prospective resource. Our best estimates for contingent and prospective resources are 8 and 13 tcf, respectively. These estimates were prepared in conjunction with DeGolyer and MacNaughton.

"We have a significant unconventional resource base of oil sands and shale gas assets," said Romanow. "When we combine this with our high quality exploration portfolio, we have substantial opportunities to fuel our future growth and create value for our shareholders."

The following table summarizes the estimated reserves and the estimated contingent and prospective resource of our oil sands and shale gas acreage positions:

Reserves(2) Contingent Resources(3,4)
Oil Sands (Billion bbls) (Billion bbls)
Proved + Prob. Low Best High
Long Lake 0.3 0.6 0.1 0.2 0.2
Kinosis 0.6 0.2 0.3 0.6
Leismer 0.6 0.8 1.1
Hanging- 0.1 0.2 0.2
Other(1) 1.5 2.3 3.4
Syncrude 0.3 0.4 0.2 0.2 0.2
Total Oil 0.6 1.6 2.7 4.0 5.8

Contingent Resources(4) Prospective
Shale Gas Reserves (tcf) (tcf) Resources(4) (tcf)
Proved + Prob. Low Best High Low Best High
Horn River
(Dilly Creek) 3 5 10
Cordova 1 3 5
Liard 5 13 23
Total Shale 4 8 15 5 13 23

Total Reserves(2) Contingent Resources(4) Resources(4)
Combined (Billion boe) (Billion boe) (Billion boe)
Proved + Prob. Low Best High Low Best High
Total Oil 0.6 1.6 2.7 4.0 5.8
Shale 0.7 1.3 2.5 0.9 2.1 3.9
0.6 1.6 3.4 5.3 8.3 0.9 2.1 3.9
(1) Includes 65% working interests in Cottonwood and 25% interest in Meadow
Creek, Corner, Chard, and 22% interest in OSLO lands.
(2) Oil sands reserves estimates are as of Dec 31, 2009 and represent
synthetic barrels
(3) Contingent resource estimates for oil sands are comprised of bitumen
(4) Contingent and prospective resource estimates are as of September 30,


Marvin Romanow, President and CEO, and members of Nexen's management team will host an investor day webcast providing an update on our strategies and opportunities along with details of our 2011 budget.

Date: November 16th, 2010

Time: 5:45 a.m. Mountain Time (7:45 a.m. Eastern Time)

We invite you to visit our website at to view a live webcast of the presentations.

The webcast will be archived under the Investor's section of our website.

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 focused on three growth strategies: oil sands and unconventional gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deep-water Gulf of Mexico. We add value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.

Information on our previously announced contingent Golden Eagle area and Appomattox resource were provided in our press releases dated September 3, 2009, and September 27, 2010 respectively. Information with respect to forward-looking statements and cautionary notes is set out below.

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 capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oilsands facilities through controlled expansions; the expectation of achieving the production design rates from our oilsands facilities; the expectation that our oilsands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected timing and associated production impact of facilities turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs; future cost recovery oil revenues from our Yemen operations; future demand for chemicals products; estimates on a per share basis; future foreign currency exchange rates; future expenditures and future allowances relating to environmental matters; 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 or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oilsands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operation of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oilsands production facilities; labour and material shortages; risk related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risk related to the imposition of moratoriums, suspensions or cancellations on our offshore exploration, development and production operations, particularly our deepwater activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions of our agents and contractors; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including, without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control. 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 2009 Annual Report on Form 10-K and Part II, Item 1A in our second quarter 2010 Quarterly Report on Form 10-Q for further discussion of the risk factors.

Cautionary Note to US Investors

In this disclosure, we may refer to "recoverable reserves", "recoverable resources", "recoverable contingent resources" and "prospective resources" which are inherently more uncertain than proved reserves or probable 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.

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's reserves disclosures are made in reliance upon exemptions granted to it 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 Canadian Oil and Gas Evaluation Handbook (COGE Handbook) standards 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 consultants.

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 in the Form 10-K:

- SEC registrants apply SEC reserves definitions and prepare their 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's technical rules in estimating reserves differ from NI 51-101 in areas such as the use of reliable technology, aerial extent around a drilled location, quantities below the lowest known oil and quantities across an undrilled fault block;

- the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using the year's 12-month average 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 reserves by geographic area only whereas NI 51-101 requires disclosure of more reserve categories and product types;

- the SEC prescribes certain information about proved and probable undeveloped reserves and future developments costs whereas NI 51-101 requirements are different;

- 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 and additional information be disclosed;

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

- the SEC does not allow proved and probable reserves to be aggregated whereas NI 51-101 requires issuers disclose such; and

- the reserves disclosures in this document have not been reviewed by the independent qualified reserves consultants whereas NI 51-101 requires them to review it.

The foregoing is a general description of the principal differences only. 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.


The resource estimates contained in this news release were made on September 30, 2010 and were prepared by qualified reserves evaluators. The estimated contingent and prospective resources in this news release reflects all of our low, high and best case of recoverable resources. A "best estimate" is the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The 'low estimate' and 'high estimate' are considered to be conservative and optimistic estimates of resources with 90% and 10% confidence respectively. Nexen's estimates of contingent and prospective resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook. Contingent resources are 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. Prospective resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.

Contingencies on resources may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific oil sands contingencies precluding these contingent resources being classified as reserves include but are not limited to: project sanction, the cost and effectiveness of steam-assisted gravity drainage application, stakeholder and regulatory approvals, access to required services and infrastructure, oil prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent oil sands resources.

Specific shale gas contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program and testing results, project sanction, the cost and effectiveness of fracing optimization, stakeholder and regulatory approvals, access to required services and field development infrastructure, gas prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent shale gas resources. In the case of shale gas prospective 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.

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
    Tim Chatten, P.Eng
    Analyst, Investor Relations
    (403) 699-4244
    Pierre Alvarez
    Vice President, Corporate Relations
    (403) 699-6291
    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7