CALGARY, ALBERTA--(Marketwire - Nov. 29, 2011) - Nexen Inc. (TSX, NYSE: NXY) today announced its 2012 production, cash flow and capital investment guidance and outlined operational expectations for the coming year.
"Our budget reflects growing cash flow, on a price-neutral basis, from significant cash margin expansion," said Marvin Romanow, Nexen's President and CEO. "We expect this increase in cash flow despite flat year-over-year production, with the start-up of the Usan project more than offsetting the expected cash flow loss from the Masila contract expiry in Yemen. Our capital investment is expected to be in-line with cash flow at current prices and supports the next stage of our action plan to fill the upgrader at Long Lake, ongoing investment in our key conventional growth initiatives, including Usan, Golden Eagle and Appomattox, and continued progress on our shale gas development."
2012 Budget Overview
-- Production estimate of 185,000 boe/d to 220,000 boe/d before royalties
(180,000 boe/d to 215,000 boe/d after royalties). This reflects a
partial year of production from Usan following start-up and the Masila
contract expiry in Yemen.
-- Price-neutral cash flow is expected to increase about 15%, largely due
to Usan contributing about $600 million in 2012.
-- Price-neutral operating cash netbacks (after-tax) are expected to
increase 18% to about $46/boe from $39/boe largely due to the
Usan netback being greater than our corporate average
netback.
-- Cash flow from operations is expected to be between $2.8 billion and
$3.3 billion assuming current prices (Brent $110/bbl, WTI $95/bbl); this
represents cash flow per share of $5.30 to $6.30.
-- Capital expenditures of $2.7 billion to $3.2 billion are being invested
to advance development projects, and production growth from Usan, Long
Lake and Golden Eagle. We are also building future capacity through
Appomattox drilling and exploration in our key basins.
-- Our budget also reflects the recent announcement of our $700 million
partial sale and joint venture agreement on our shale gas lands in
northeast British Columbia.
2012 Production Guidance
Estimated Average Daily Production before Royalties
Crude Oil, NGLs and
Natural Gas
(mboe/d) Q1 2012 Q2 2012 Q3 2012 Q4 2012
----------------------------------------------------------------------------
Buzzard 75-95 75-95 50-60 75-95
Other UK 26-34 26-34 20-26 25-32
Syncrude 22-24 18-20 22-24 22-24
Long Lake (bitumen) 20-25 13-17 21-28 22-28
West Africa 0-10 13-30 20-35 22-35
United States 15-20 15-20 13-17 15-17
Other Canada 15-20 15-18 15-17 15-20
Other Countries 2 2 2 2
--------------------------------------------------------
approx. approx. approx. approx.
180 - 220 185 - 225 165 - 200 205 - 240
Yemen
Estimated Average Daily Production before Royalties
Crude Oil, NGLs and
Natural Gas
(mboe/d) 2012 Annual 2011 Annual
----------------------------------------------------------------------------
Buzzard 70 - 85 61 - 66
Other UK 24 - 32 28 - 30
Syncrude 21 - 23 21 - 22
Long Lake (bitumen) 19 - 25 18 - 20
West Africa 14 - 28 -
United States 15 - 19 23 - 24
Other Canada 15 - 19 20 - 21
Other Countries 2 2
---------------------------------------------------------
approx. approx.
185 - 220 170 - 180
Yemen 32 - 35
approx.
200 - 215
2011 fourth quarter production to date has averaged about 203,000 boe/d; Buzzard production has averaged approximately 175,000 boe/d (75,000 boe/d net to Nexen) as we begin to operate the fourth platform on a fully-integrated basis. Our year-to-date production is approximately 206,000 boe/d.
In 2012, we expect overall production before royalties to be about flat relative to 2011 production. The start-up and partial year of production at Usan, growth at Long Lake and expected higher operating rates at Buzzard, offset the contract expiry at Masila and extended downtime due to regulatory-driven inspections at Buzzard and Long Lake.
Our guidance does not reflect any production from Yemen given the expiry of the Masila contract on December 17th, 2011. Our contract for Block 51 (East Al-Hajr) in Yemen, which currently produces about 6,000 to 8,000 bbls/d net to Nexen, expires in 2023. We are currently evaluating alternatives with respect to Block 51 and future activities in the country.
Production after royalties is expected to grow faster than production before royalties as we replace high-royalty Yemen production with higher-value barrels from West Africa.
The 2012 production results are expected to vary within our range based on three primary factors: the timing of start-up and pace of ramp-up at Usan, variability at Buzzard as we increase the rate through the fourth platform, and the pace of production growth at Long Lake.
The quarterly production variability primarily reflects the timing and pace of ramp-up at Usan together with planned shutdowns at Buzzard and Long Lake.
Usan
Our largest source of new production in 2012 is our Usan field. We expect to achieve first oil in the first half of 2012.
Usan's facility capacity is 36,000 bbls/d net to Nexen; actual production rates will vary within that capacity based on several factors including well performance, facility uptime, and pace of ramp-up.
Buzzard
At Buzzard, we expect production levels to return to capacity, although our expectations allow for the possibility of fluctuations as we continue to increase the rate through the fourth platform to take advantage of the full set of wells now available. The guidance also accounts for an extended four-week shutdown in the third quarter for Buzzard's five-year regulatory inspection.
Long Lake
Long Lake is expected to continue to ramp-up throughout 2012 as:
-- Pad 11 continues to increase from its current rate of 2,000 bbls/d as
it moves toward our expectation of 4,000 to 8,000 bbls/d.
-- Most of the good quality wells on the original 10 pads continue to
improve and we expect this to continue into 2012.
-- First production from higher quality resource on pads 12 and 13 is
expected in the latter half of next year. First steam is expected at pad
12 next spring and at pad 13 in late summer. Initial production from
these pads is expected after a three to six month soak period.
-- Partially offsetting this growth will be the three-year regulatory
inspection and concurrent turnaround at Long Lake. We expect about three
weeks of SAGD downtime as part of this extended turnaround; the upgrader
is expected to be down for about six weeks, which will result in some
sales of diluted bitumen during the quarter.
Other Areas
Non-Buzzard UK production is expected to be flat relative to 2011 as recent tie-backs at Blackbird and Telford offset declines. Our Rochelle gas development is expected to come on-stream late in the year.
Syncrude production is expected to be lower in the second quarter as a result of planned annual maintenance.
Natural declines are expected to affect production from our existing Gulf of Mexico assets and our conventional gas and CBM operations in western Canada.
Shale gas volumes are expected to increase in the fourth quarter from the start-up of our 18-well pad, but the year-over-year change in our production will be minimal following the sale of a 40% working interest to our joint venture partner.
2012 Cash Flow Outlook
For 2012, we expect cash flow from operations to be between $2.8 billion and $3.3 billion assuming current oil prices of approximately $110/bbl Brent and $95/bbl WTI. This reflects a higher after-tax operating cash netback on a price neutral basis; we expect it to increase 18% to about $46/boe from $39/boe largely due to an anticipated netback at Usan that is greater than our corporate average netback.
Our cash flow sensitivity is approximately $22 million per $1 change in Brent prices, $15 million per $1 change in WTI prices, and $16 million per $1 change in natural gas prices.
2012 Capital Investment Program
----------------------------------------------------------------------------
Estimated 2012 Capital Investment
(Cdn$ millions)
----------------------------------------------------------------------------
Conventional Oil & Gas 1,725-1,900
Golden Eagle 375-400
Usan 375-400
UK Tie-back Developments 300
Exploration & Appraisal 400-475
Other 275-325
Oil Sands 775-1,050
Long Lake & Kinosis 475-725
Other SAGD 75
Syncrude 225-250
Shale Gas 150-200
Northeast BC 50-75
Poland & Colombia 100-125
Other 50
---------------------------------
Total Estimated Capital Investment 2,700-3,200
----------------------------------------------------------------------------
Conventional Oil & Gas
Our capital investment plans for our conventional assets are focused on developing our existing discoveries and exploring three primary offshore basins: the UK North Sea, West Africa and the Gulf of Mexico.
The Usan development, offshore West Africa, is in the final stages of commissioning, with start-up expected in the first half of 2012. Our total capital investment to date is approximately $1.5 billion and we expect to spend between $375 and $400 million in 2012. Our West Africa investment program will allow us to continue with production and injector well drilling, and resume exploration and appraisal drilling in West Africa with the Usan West appraisal well and an exploration well at Owowo West to follow up on our previous discovery at Owowo South B.
In the UK North Sea, we recently received government approval for our Golden Eagle development, which is expected to produce about 70,000 boe/d (26,000 boe/d net to Nexen) starting approximately three years from now. In 2012, we plan to invest between $375 million and $400 million here, which represents approximately one third of our total project investment. This spending will be primarily directed towards fabrication of the platforms and facilities, with drilling scheduled to start in 2013. Golden Eagle is expected to generate a 10% rate of return with commodity prices at roughly half of current levels.
We plan to spend about $200 million to sustain production from our existing UK assets and approximately $300 million to advance various tie-back projects in the North Sea, including the development of our Rochelle field tie-back to Scott, and additional drilling at Blackbird and Telford.
In the Gulf of Mexico, we are progressing the drilling at Kakuna, our first operated exploration well since the end of the moratorium. We also have a robust program planned for the Appomattox area with further exploration and appraisal of our Appomattox discovery, an appraisal well at Vicksburg and an exploration well in the nearby Petersburg area. We plan to drill a total of four wells in this area in 2012.
Exploration & Appraisal
We have a 28-well exploration and appraisal program planned for 2012 and anticipate spending approximately 20% of our capital investment program in this area. Success from this program will help us move our Appomattox, Polecat and Owowo discoveries closer to development while unlocking our next set of growth prospects in our core areas through high-impact exploration wells at Kakuna, Angel Fire, North Uist and Owowo West. Our unconventional exploration programs are aimed at evaluating significant additional resource potential in Poland (tight oil and shale gas) and Colombia (shale gas).
Our exploration and appraisal program in 2012 is targeting mean risked resource potential of approximately 550 mmboe (2,000 mmboe unrisked including 1,350 mmboe relating to unconventional exploration activities in Poland and Colombia) net to our working interest.
----------------------------------------------------------------------------
Exploration & Appraisal Profile # of wells
----------------------------------------------------------------------------
Gulf of Mexico
Appomattox & Area Wells 4
Angel Fire & Kakuna Exploration Wells 2
North Sea
UK Exploration Wells 4
UK Appraisal Wells 4
West Africa Exploration & Appraisal Wells 2
Other
Canadian Tight Oil 2
Colombia 4
Poland 6
----------
Total 28
----------------------------------------------------------------------------
Oil Sands
In the oil sands, our capital investment plans are focused on filling the Long Lake upgrader with bitumen. Our plan to achieve this includes adding new wells in areas where the reservoir characteristics are similar to our best producing wells at Long Lake. This plan is expected to provide us with a very attractive return on incremental capital as each incremental barrel of production contributes significantly to cash flow and profitability given the primarily fixed cost nature of the Long Lake operation.
In addition to continuing to optimize production from the initial 10 pads, our plans to fill the upgrader include:
Number of Wells Expected Rates
bbls/d
----------------------------------------------------------------------------
Pad 11 10 4,000 - 8,000
Pads 12 & 13 18 11,000 - 17,000
Pads 14 & 15 10-12 6,000 - 9,000
Kinosis 25-30 15,000 - 25,000
There are a number of milestones to watch for during 2012 on our action plan:
-- Continued production growth on pad 11, which is currently producing
about 2,000 bbls/d.
-- On pad 12, drilling has been completed and we expect to begin steaming
the reservoir next spring. First production from this pad is expected
three to six months later following the steam soak period. Pad 12 will
be our first producing pad where we have specifically targeted high
quality resource based on the operating and reservoir knowledge we have
gained.
-- Drilling on pad 13 is expected to be completed shortly, with first steam
to follow in the fall of 2012. Production from this pad should commence
around the end of 2012. Once ramped-up, pads 12 and 13 are expected to
produce 11,000-17,000 bbls/d of bitumen.
-- On pads 14 and 15, we are currently working through the regulatory
approval process. These wells are expected to be drilled either next
winter or the following winter, depending on the timing of regulatory
approvals. They are expected to produce 6,000-9,000 bbls/d of bitumen at
maturity.
-- At Kinosis, we plan to drill 25-30 new wells. We currently have
regulatory approval for a 140,000 bbls/d SAGD operation. We have
submitted an amendment to the approval to allow us to tie-in these wells
to the Long Lake facilities. We expect these wells to be drilled in
either 2012 or 2013 depending on regulatory approval. These wells are
expected to contribute 15,000-25,000 bbls/d of bitumen once fully
ramped-up. Steam for these wells will be provided by four once-through
steam generators which will be installed at Kinosis, while using water
supplied by the Long Lake plant.
The incremental investment for the new wells, steam generators and associated infrastructure is currently estimated to be approximately $900 million, net to our working interest, over the next three years. This is in addition to the previously expected sustaining capital of about $200 million required to mitigate future declines from pads 1-10 as the wells mature. In 2012, we plan to spend between $200 million and $425 million on these initiatives, depending on regulatory approvals. Our oil sands investment program also includes completion of a 200 core hole program being drilled this winter.
We continue to invest in our non-operated oil sands projects as well. At Syncrude, we expect to spend between $225 million and $250 million to sustain production and cash flow. We also continue to advance our SAGD Hangingstone project, which we expect to sanction next year. Subject to regulatory approval, this would add about 6,000 bbls/d of bitumen to our production at full rates. Our partner at Hangingstone is JACOS, who is the operator.
Shale Gas
Our capital investment plans on our Horn River acreage are focused on the continued successful execution of our drilling and completion programs.
Together with our new partners, we plan to invest approximately $400 million ($60 million net to Nexen after capital carry) primarily on expanding our processing capacity and completing the 18-well pad that we are currently drilling. This pad is expected to begin producing in the fourth quarter of 2012 and our production is expected to ramp-up to a peak of approximately 155 mmcf/d in early 2013. Our future Horn River development plan will be finalized with our new partner in 2012.
The remainder of our shale gas spending will be directed at developing international plays in Poland and Colombia. We plan to participate in six play evaluation exploration wells in Poland and drill three wells in Colombia in 2012.
Webcast
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 2012 budget.
Date: December 1st, 2011
Time: 7:15 a.m. Mountain Time (9:15 a.m. Eastern Time)
We invite you to visit our website at www.nexeninc.com to view a live webcast of the presentations.
The webcast will be archived under the Investors' 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 shale gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deepwater 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 with respect to forward-looking statements and cautionary notes is set out below.
Forward-Looking Statements
Certain statements in this release constitute "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook", "forecast" or other similar words and include statements relating to or associated with individual wells, regions or projects.
Any statements as to possible future crude oil, natural gas or chemicals prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our 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; the expectation of negotiating of an extension to certain of our production sharing agreements; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; 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 and our ability to comply therewith; dates by which certain areas will be developed, come on stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
All of the forward-looking statements in this release are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
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; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of 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 and financial circumstances of our agents, counterparties, contractors, and joint venture parties; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on our assessment of all information at that time. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof 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 the Risk Factors contained in our 2010 Annual Information form, and to the Quantitative Disclosures about Market Risk and our Forward Looking Statements contained in our 2010 Management Discussion and Analysis.
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 Information Form available under our profile on SEDAR at www.sedar.com for further reserves disclosure.
Cautionary Note to Canadian Investors
Nexen has received an exemption from the securities regulatory authorities in the various provinces of Canada from certain requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") that permits us to disclose reserves estimates and related disclosures that have been prepared in accordance with SEC requirements.
As a result of this exemption, Nexen's disclosures may differ from other Canadian companies and investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with SEC requirements and those prepared in accordance with NI 51-101:
-- SEC reserves estimates are based upon different reserves definitions and
are prepared in accordance with generally recognized industry practices
in the US whereas NI 51-101 reserves are based on definitions and
standards promulgated by the Canadian Oil and Gas Evaluation Handbook
("COGE Handbook") and generally recognized industry practices in Canada;
-- SEC reserves definitions differ from NI 51-101 in areas such as the use
of reliable technology, areal 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 monthly average prices and costs held
constant whereas NI 51-101 requires disclosure of reserves and related
future net revenues using forecast prices and costs;
-- the SEC mandates disclosure of reserves by geographic area whereas NI
51-101 requires disclosure of reserves by additional categories and
product types;
-- the SEC does not require the disclosure of future net revenue of proved
and proved plus probable reserves using forecast pricing at various
discount rates;
-- the SEC requires future development costs to be estimated using existing
conditions held constant, whereas NI 51-101 requires estimation using
forecast conditions;
-- the SEC does not require the validation of reserves estimates by
independent qualified reserves evaluators or auditors, whereas, without
an exemption noted below, NI 51-101 requires issuers to engage such
evaluators or auditors to evaluate, audit or review reserves and related
future net revenue attributable to those reserves; and
-- the SEC does not allow proved and probable reserves to be aggregated
whereas NI 51-101 requires issuers to make such aggregation.
The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material for certain properties. Please also note:
-- 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 has also received an exemption from NI 51-101 that permits us to forego the requirement to have our reserves and related future net revenue attributable to our reserves evaluated, audited or reviewed by an independent qualified reserves evaluator or auditor. Accordingly, our future net revenue and reserves estimates are based on internal evaluations. Due to the extent and expertise of our internal reserves evaluation resources, our staff's familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated reserves estimates is not materially less than would be generated by an independent reserves evaluator.
Resources
The resource estimates contained in this news release were announced on September 27, 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:
Vice President, Investor Relations
(403) 699-4230
Pierre Alvarez
Vice President, Corporate Relations
(403) 699-6291
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
www.nexeninc.com