EXHIBIT 99.1
------------
N E X E N
NEXEN IN. 801-7th Ave. SW Calgary, AB Canada T2P 3P7
T 403 699-4000 F 403 699-5776 www.nexeninc.com
N E W S R E L E A S E
For immediate release
CURRENT PRODUCTION AT ANNUAL HIGH FOLLOWING START-UP OF NEW PROJECTS
CALGARY, ALBERTA, OCTOBER 28, 2009 -Throughout the third quarter, we made
significant progress in advancing our strategies. We successfully executed the
planned turnaround at Long Lake, announced the largest discovery in the UK North
Sea in the last ten years after Buzzard, and moved our breakevens down on our
Horn River shale gas play. We also started up Ettrick in the North Sea and added
incremental volumes from successful infill drilling at Telford. Longhorn in the
Gulf of Mexico started up earlier this week. Current production rates are now at
an annual high. A summary of our quarterly results, together with recent
highlights, is as follows:
o CASH FLOW OF $379 MILLION ($0.73/SHARE) AND NET INCOME OF $122 MILLION
($0.23/SHARE)
o PRODUCTION BEFORE ROYALTIES OF 214,000 BOE/D IMPACTED BY TURNAROUND AND
MAINTENANCE ACTIVITIES
o CURRENT PRODUCTION BEFORE ROYALTIES OF 275,000 BOE/D AND INCREASING AS
ETTRICK, LONGHORN AND LONG LAKE CONTINUE TO RAMP UP
o SUCCESSFUL TURNAROUND AT LONG LAKE; BITUMEN VOLUMES RAMPING UP; UPGRADER
START-UP IMMINENT
o SUCCESSFUL TELFORD STEP-OUT WELL IN THE NORTH SEA AND SIGNIFICANT SHALE GAS
PROGRESS IN THE HORN RIVER
o KNOTTY HEAD APPRAISAL WELL CURRENTLY DRILLING
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
---------------------- ----------------------
(Cdn$ millions) 2009 2008 2009 2008
- -----------------------------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 214 249 235 257
After Royalties 184 209 206 214
Net Sales 1,097 2,213 3,345 6,154
Cash Flow from Operations(2) 379 1,685 1,379 3,670
Per Common Share ($/share)(2) 0.73 3.20 2.65 6.95
Net Income 122 886 277 1,896
Per Common Share ($/share) 0.23 1.68 0.53 3.59
Capital Investment(3), excluding Acquisitions 671 763 2,178 2,219
Acquisitions(4) - - 755 2
- -----------------------------------------------------------------------------------------------
(1) Production includes our share of Syncrude oil sands. US investors should
read the Cautionary Note to US Investors at the end of this release.
(2) For reconciliation of this non-GAAP measure see Cash Flow from Operations
on pg. 9.
(3) Includes geological and geophysical expenditures.
(4) 2009 represents acquisition of additional 15% interest in Long Lake from
Opti Canada Inc.
1
FINANCIAL RESULTS
Quarterly cash flow from operations was $379 million and net income was $122
million compared to $1.7 billion and $886 million a year ago. Planned
maintenance and turnarounds impacted production volumes and reduced quarterly
cash flow by approximately $120 million. At the end of the quarter, we were
carrying approximately three quarters of a million barrels of inventory. Cash
flow from the sale of this inventory will be realized in the fourth quarter.
The decrease from last year also reflects the impact of lower commodity prices
and some significant items included in income last year. In the third quarter,
WTI averaged US$68/bbl compared to US$118/bbl a year ago. Last year, our cash
flow included a one-time income tax recovery and earnings included a recovery of
stock-based compensation following the drop in our share price at the start of
the economic crisis.
Compared to the previous quarter, cash flow from operations was $64 million
less. This reflects the impact of maintenance and turnaround activities and
higher estimated cash taxes offset in part by an improvement in oil prices. The
higher taxes reflect the impact of increasing commodity prices and increasing
North Sea production volumes from the start-up of new projects. With 85% of our
production weighted to oil, we continue to be highly levered to increasing oil
prices.
QUARTERLY PRODUCTION--TURNAROUNDS COMPLETE AND CURRENT PRODUCTION AT ANNUAL HIGH
Crude Oil, NGLs and PRODUCTION BEFORE ROYALTIES PRODUCTION AFTER ROYALTIES
Natural Gas (mboe/d) Q3 2009 Q2 2009 Q3 2009 Q2 2009
- ------------------------------------------------------------- -----------------------------------
North Sea 76 101 76 101
Yemen 49 51 28 29
Canada - Oil & Gas 38 38 34 33
Canada - Bitumen 6 9 6 9
United States 20 22 18 20
Other Countries 2 4 2 3
Syncrude 23 15 20 13
---------------------------------- -----------------------------------
TOTAL 214 240 184 208
---------------------------------- -----------------------------------
Third quarter production volumes averaged 214,000 boe/d (184,000 boe/d after
royalties). Volumes were lower due to turnarounds and maintenance activities at
a number of our fields.
At Buzzard, production was shut-in for four weeks for the installation of the
jacket for the fourth platform. This shut down was scheduled to coincide with
maintenance to the Forties pipeline. As a result, Buzzard contributed
approximately 60,000 boe/d (138,000 boe/d gross) to our production volumes
compared to 87,500 boe/d in the second quarter. Buzzard has since returned to
full rates and is currently producing between 200,000 and 220,000 boe/d gross.
At Scott/Telford, we completed a major turnaround which resulted in the fields
being shutdown for approximately five weeks. The fields are back on-stream and
additional production from the recently announced Telford step-out well has
allowed us to almost double our production from the Scott platform. This well
encountered 254 feet of high quality net oil pay. We still see additional upside
at Telford and expect to conduct follow-up drilling in 2010.
With all of our North Sea fields back online and with growing volumes from the
ramp-up of Ettrick, our UK production volumes are at record highs. Our presence
here is well established and we are the third largest operator of oil production
in the UK.
At Long Lake, we successfully completed the previously announced turnaround to
replace valves, clean-out our hot lime softeners, isolate our water treatment
trains and perform a number of other planned maintenance activities to improve
2
reliability and operability. We also completed the installation of electric
submersible pumps (ESPs) in some of our SAGD wells. With the turnaround complete
we have resumed steaming our wells and bitumen volumes are ramping up. In the
Gulf of Mexico, maintenance activities were completed at third party operated
facilities which impacted production from our Wrigley and Aspen fields. At
Syncrude, production increased in the third quarter following the completion of
turnaround activity throughout the first half of the year.
"We previously announced that our third quarter would be impacted by planned
turnarounds on a number of fields," stated Marvin Romanow, Nexen's President and
Chief Executive Officer. "With the completion of these activities and the start
up of new production, current production is 275,000 boe/d and growing. With
production ramping up at Ettrick, Longhorn and Long Lake, we expect fourth
quarter production volumes to be strong."
GLOBAL EXPLORATION--EXCITEMENT CONTINUES TO BUILD
UK NORTH SEA
The Golden Eagle area has emerged as a significant development opportunity. Our
current estimates of contingent recoverable resource range between 150 and 275
mmboe. We expect development of the area will be economic with oil prices as low
as US$40/bbl and require standalone facilities due to its size. Project sanction
is targeted for 2010. Appraisal activity continues and we have now drilled 13
wells in the area.
"The Golden Eagle area is the largest discovery in the UK North Sea in the last
10 years after Buzzard," commented Romanow. "Like Buzzard, this discovery is a
hard to find stratigraphic trap. Our geological model is working well in this
mature basin."
As we move into 2010, we are finalizing exploration plans to drill the North
Uist prospect, west of the Shetland Islands and the Brand prospect in the
Norwegian North Sea. These prospects have target sizes well above our typical
North Sea target size.
OFFSHORE WEST AFRICA
Earlier this year we completed drilling an exploration well in the southern
portion of Oil Prospecting License (OPL) 223, offshore West Africa.
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.
We expect to announce drilling results shortly.
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
well.
"We continue to be excited about our exploration opportunities offshore West
Africa," said Romanow. "This is a very oily part of the world which improves our
chances of success."
DEEP-WATER GULF OF MEXICO
In the Gulf of Mexico, the arrival of the Ensco 8501 rig has allowed us to start
drilling our Knotty Head appraisal well. The well spud earlier this month and we
expect results in the second quarter of 2010. A second deep-water drilling rig
is expected to arrive in mid 2010. This will allow us to start drilling more of
our identified prospects.
In the Eastern Gulf, we recently spud the Appomattox prospect, which is located
six miles west of our Vicksburg discovery. Drilling results are expected early
next year. During the quarter, we completed drilling the Antietam prospect. The
well encountered thick good quality sand, but was wet. We have a 25% interest in
Vicksburg and a 20% interest in Appomattox and Shiloh, an earlier discovery.
Shell operates all three.
3
LONG LAKE--TURNAROUND COMPLETE AND MOVING FULL STEAM AHEAD
The turnaround at Long Lake is complete and we have resumed steaming our wells.
Steam production is increasing. Bitumen production is back up to pre-turnaround
rates of 10,000-12,000 bbls/d (gross) and growing. Upgrader start-up is imminent
now that we have sufficient bitumen feedstock.
The turnaround activities focused on replacing valves, cleaning out the hot lime
softeners and isolating the water treatment trains, and we performed a number of
other planned maintenance activities to improve reliability and operability.
These activities were successfully completed within the period of scheduled
downtime. We also installed ESPs in a number of our SAGD wells. This will allow
us to have better pressure control and ultimately reduce our overall steam to
oil ratio ("SOR").
In addition, we recently completed the steam de-bottleneck project which will
increase our SAGD steam production capacity to over 230,000 bbls/d. Start-up of
the de-bottleneck project will proceed as required to support the SAGD ramp-up.
We continue to expect a long term SOR of 3.0 over the life of the project.
With respect to the Upgrader, we have now operated all units including the
solvent de-asphalter and the thermal cracker. These units are necessary to
achieve our target yield of approximately 80%. In addition, Syngas is being used
in all SAGD operations. This allows us to decrease operating costs by reducing
the requirement for purchased natural gas.
"Following the addition of steam to our hot lime softeners earlier this year,
the successful execution of our turnaround program a few weeks ago and the
recent completion of our steam de-bottleneck project, we are in great shape to
get back on the ramp-up curve we saw prior to the start-up of the upgrader,"
commented Romanow. "While we expect there will be periods of downtime as bitumen
production ramps up, we anticipate continuing improvements in operational
stability."
Phase 1 of our Long Lake project is designed to produce 72,000 bbls/d of gross
bitumen, upgraded to approximately 60,000 bbls/d (39,000 bbls/d, net to us) of
PSCTM. We have a 65% interest in the project and the joint venture lands. We are
the sole operator of the resource and the upgrader. We expect Long Lake will
generate significant value with 40 years of production at a $10/bbl margin
advantage.
UK NORTH SEA--FIRST OIL PRODUCED AT ETTRICK
Our Ettrick development in the North Sea produced first oil in mid August and we
have tested the floating production, storage and offloading vessel (FPSO) up to
its design rates. Field production will ramp-up as we commission the gas system.
The project is expected to add approximately 12,000 to 16,000 boe/d to our
production volumes for the remainder of the year. We have a 2008 discovery at
Blackbird which could be a future tie-back to Ettrick. We operate both Ettrick
and Blackbird, with a 79.73% working interest in each.
GULF OF MEXICO--LONGHORN NOW ON-STREAM
Earlier this week, we started production from Longhorn. The field is expected to
reach peak production of approximately 200 mmcf/d or 33,000 boe/d gross (50
mmcf/d or 8,000 boe/d, net to us) early next year. We have a 25% non-operated
working interest in this project and ENI is the operator.
4
HORN RIVER SHALE GAS--BREAKEVENS COMING DOWN
Following the conclusion of our recent three-well drilling and completion
program, we continue to make significant progress on our substantial Horn River
shale gas position in north-east British Columbia. With five shale gas wells now
on-stream, we are producing approximately 15 mmcf/d with the majority of
production coming from the three new wells. These wells have a higher frac
density than our earlier wells. Our land position here could support 500 to 700
wells.
Substantial cost savings and productivity improvements were realized with this
drilling and completion program. 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. Two of the wells were completed with eight
fracs, while the third well was completed with ten fracs.
"We are making excellent progress in bringing down our Horn River breakevens by
decreasing costs and increasing well productivity, and there is more upside to
come," said Romanow. "We are in the process of developing an eight-well pad
drilling program for this winter. These wells will be longer than our current
wells with eighteen fracs per well. The following winter we plan to drill an
eighteen-well pad which we expect will drive our breakevens down further."
We have approximately 88,000 acres in the Dilly Creek area of the Horn River
basin 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 companywide
total proved reserves. Further appraisal activity is required before these
estimates can be finalized and commerciality established.
OFFSHORE WEST AFRICA--USAN DEVELOPMENT CONTINUES
Development of the Usan field on block OML 138, offshore Nigeria is fully
underway. The field development plan includes a FPSO vessel with a storage
capacity of two million barrels of oil. Development drilling is underway and the
FPSO hull is under construction. 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.
MARKETING UPDATE
We are making progress on the strategic review of our marketing business. Data
rooms are ready and numerous parties have expressed interest. Our marketing
division continues to contribute to our quarterly results, generating $30
million of cash flow in the third quarter.
QUARTERLY DIVIDEND
The Board of Directors has declared the regular quarterly dividend of $0.05 per
common share payable January 1, 2010, to shareholders of record on December 10,
2009. Shareholders are advised that the dividend is an eligible dividend for
Canadian Income Tax purposes.
Nexen Inc. is an independent, Canadian-based global energy company, listed on
the Toronto and New York stock exchanges under the symbol NXY. We are uniquely
positioned for growth in the North Sea, Western Canada (including the Athabasca
oil sands of Alberta and unconventional gas resource plays such as shale gas),
deep-water Gulf of Mexico, offshore West Africa and the Middle East. We add
5
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.
For further information, please contact:
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
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
www.nexeninc.com
CONFERENCE CALL
Marvin Romanow, President and CEO, and Kevin Reinhart, Senior Vice-President and
CFO will host a conference call to discuss our financial and operating results
and expectations for the future.
Date: October 28, 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:
416-340-8018 (Toronto)
866-225-0198 (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 6827570 followed by the pound sign. A live and on demand webcast of the
conference call will be available at www.nexeninc.com.
FORWARD-LOOKING STATEMENTS
CERTAIN STATEMENTS IN THIS REPORT CONSTITUTE "FORWARD-LOOKING STATEMENTS"
(WITHIN THE MEANING OF THE UNITED STATES PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995) 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.
6
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:
o 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;
o SUBSTITUTE THOSE SEC DISCLOSURES FOR MUCH OF THE ANNUAL DISCLOSURE
REQUIRED BY NI 51-101; AND
o 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:
o 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;
o 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;
o 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;
o 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;
o 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;
o 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;
o 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);
7
o 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
o 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:
o 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
o 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.
RESOURCES
NEXEN'S ESTIMATES OF CONTINGENT RESOURCES ARE BASED ON DEFINITIONS SET OUT
IN THE CANADIAN OIL AND GAS EVALUATION HANDBOOK WHICH GENERALLY DESCRIBE
CONTINGENT RESOURCES AS THOSE QUANTITIES OF PETROLEUM ESTIMATED, AS OF A
GIVEN DATE, TO BE POTENTIALLY RECOVERABLE FROM KNOWN ACCUMULATIONS USING
ESTABLISHED TECHNOLOGY OR TECHNOLOGY UNDER DEVELOPMENT, BUT WHICH ARE NOT
CURRENTLY CONSIDERED TO BE COMMERCIALLY RECOVERABLE DUE TO ONE OR MORE
CONTINGENCIES. SUCH CONTINGENCIES MAY INCLUDE, BUT ARE NOT LIMITED TO,
FACTORS SUCH AS ECONOMIC, LEGAL, ENVIRONMENTAL, POLITICAL AND REGULATORY
MATTERS OR A LACK OF MARKETS. SPECIFIC CONTINGENCIES PRECLUDING THESE
CONTINGENT RESOURCES BEING CLASSIFIED AS RESERVES INCLUDE BUT ARE NOT
LIMITED TO: FUTURE DRILLING PROGRAM RESULTS, DRILLING AND COMPLETIONS
OPTIMIZATION, STAKEHOLDER AND REGULATORY APPROVAL OF FUTURE DRILLING AND
INFRASTRUCTURE PLANS, ACCESS TO REQUIRED INFRASTRUCTURE, ECONOMIC FISCAL
TERMS, 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.
8
NEXEN INC.
FINANCIAL HIGHLIGHTS
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
- ------------------------------------------------------------------------------------------------------------
Net Sales 1,097 2,213 3,345 6,154
Cash Flow from Operations 379 1,685 1,379 3,670
Per Common Share ($/share) 0.73 3.20 2.65 6.95
Net Income 122 886 277 1,896
Per Common Share ($/share) 0.23 1.68 0.53 3.59
Capital Investment (1) 655 725 2,119 2,147
Acquisitions - - 755 2
Net Debt (2) 5,532 3,914 5,532 3,914
Common Shares Outstanding (millions of shares) 521.8 521.0 521.8 521.0
-----------------------------------------------------
(1) Includes oil and gas development, exploration, and expenditures for other
property, plant and equipment.
(2) Net debt is defined as long-term debt and short-term borrowings less cash
and cash equivalents.
CASH FLOW FROM OPERATIONS (1)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
- -------------------------------------------------------------------------------------------------------------
Oil & Gas and Syncrude
United Kingdom 400 1,056 1,382 2,857
Yemen (2) 79 195 244 543
Canada 23 131 85 344
United States 34 93 87 405
Other Countries 13 45 30 108
Marketing 29 (65) 147 (216)
Syncrude 70 151 98 350
-----------------------------------------------------
648 1,606 2,073 4,391
Chemicals 29 28 84 60
-----------------------------------------------------
677 1,634 2,157 4,451
Interest and Other Corporate Items (147) (56) (369) (203)
Income Taxes (3) (151) 107 (409) (578)
-----------------------------------------------------
Cash Flow from Operations (1) 379 1,685 1,379 3,670
=====================================================
(1) Defined as cash flow from operating activities before changes in non-cash
working capital and other. We evaluate our performance and that of our
business segments based on earnings and cash flow from operations. Cash
flow from operations is a non-GAAP term that represents cash generated from
operating activities before changes in non-cash working capital and other
and excludes items of a non-recurring nature. We consider it a key measure
as it demonstrates our ability and the ability of our business segments to
generate the cash flow necessary to fund future growth through capital
investment and repay debt. Cash flow from operations may not be comparable
with the calculation of similar measures for other companies.
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities 461 968 1,359 3,299
Changes in Non-Cash Working Capital (113) 840 (193) 468
Other 49 (117) 234 (79)
Impact of Annual Crude Oil Put Options (18) (6) (21) (18)
---------------------------------------------------
Cash Flow from Operations 379 1,685 1,379 3,670
===================================================
Weighted-average Number of Common Shares Outstanding
(millions of shares) 521.7 525.9 521.0 528.3
---------------------------------------------------
Cash Flow from Operations Per Common Share ($/share) 0.73 3.20 2.65 6.95
===================================================
(2) After in-country cash taxes of $39 million for the three months ended
September 30, 2009 (2008 - $81 million) and $105 million for the nine
months ended September 30, 2009 (2008 - $239 million).
(3) Excludes in-country cash taxes in Yemen.
9
NEXEN INC.
PRODUCTION VOLUMES (BEFORE ROYALTIES) (1)
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- -------------------------------------------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 73.7 100.0 91.6 102.0
Yemen 48.7 54.1 51.5 58.0
Canada 14.2 16.0 14.9 16.2
United States 9.5 8.5 10.6 11.2
Long Lake Bitumen (2) 5.5 5.2 7.6 3.0
Other Countries 2.6 5.7 3.9 5.7
Syncrude (mbbls/d) (3) 22.5 22.9 19.1 20.4
-------------------------------------------------------------
176.7 212.4 199.2 216.5
-------------------------------------------------------------
Natural Gas (mmcf/d)
United Kingdom 17 17 18 19
Canada 143 133 139 128
United States 63 70 58 94
-------------------------------------------------------------
223 220 215 241
-------------------------------------------------------------
Total Production (mboe/d) 214 249 235 257
=============================================================
PRODUCTION VOLUMES (AFTER ROYALTIES)
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- ------------------------------------------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 73.7 100.0 91.6 102.0
Yemen 28.3 29.9 31.0 30.3
Canada 10.9 12.0 11.6 12.3
United States 8.5 7.3 9.6 9.7
Long Lake Bitumen (2) 5.5 5.2 7.6 3.0
Other Countries 2.4 5.1 3.6 5.3
Syncrude (mbbls/d) (3) 20.0 18.9 17.6 17.3
------------------------------------------------------------
149.3 178.4 172.6 179.9
------------------------------------------------------------
Natural Gas (mmcf/d)
United Kingdom 17 17 17 19
Canada 137 107 130 107
United States 56 60 52 80
------------------------------------------------------------
210 184 199 206
------------------------------------------------------------
Total Production (mboe/d) 184 209 206 214
============================================================
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Pre-operating revenues and costs associated with Long Lake bitumen are
capitalized as development costs until we reach commercial operations.
(3) Currently considered a mining operation for US reporting purposes.
10
NEXEN INC.
OIL AND GAS PRICES AND CASH NETBACK (1)
TOTAL
Quarters - 2009 Quarters - 2008 YEAR
-----------------------------|-----------------------------------------|--------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd | 1st 2nd 3rd 4th | 2008
- -----------------------------------------------------------------------|-----------------------------------------|--------
PRICES:
WTI Crude Oil (US$/bbl) 43.08 59.62 68.30 | 97.90 123.98 117.98 58.73 99.65
Nexen Average - Oil (Cdn$/bbl) 50.41 68.32 72.95 | 93.00 118.00 115.56 59.90 96.92
NYMEX Natural Gas (US$/mmbtu) 4.48 3.81 3.44 | 8.75 11.48 8.95 6.41 8.90
Nexen Average - Gas (Cdn$/mcf) 5.11 3.77 3.04 | 7.97 10.21 8.65 6.34 8.44
- -----------------------------------------------------------------------|--------------------------------------------------
|
NETBACKS: |
CANADA - HEAVY OIL |
Sales (mbbls/d) 15.4 14.7 14.0 | 16.2 16.4 16.0 16.2 16.2
|
Price Received ($/bbl) 35.35 56.05 59.88 | 65.94 93.16 97.91 41.14 74.51
Royalties & Other 6.86 12.83 13.47 | 16.65 22.61 24.24 8.81 18.07
Operating Costs 15.42 16.41 16.21 | 15.76 17.17 16.99 16.69 16.66
- -----------------------------------------------------------------------|--------------------------------------------------
Netback 13.07 26.81 30.20 | 33.53 53.38 56.68 15.64 39.78
- -----------------------------------------------------------------------|--------------------------------------------------
CANADA - NATURAL GAS |
Sales (mmcf/d) 137 134 136 | 127 126 133 138 131
|
Price Received ($/mcf) 4.75 3.42 2.85 | 7.57 9.67 8.00 6.06 7.73
Royalties & Other 0.59 0.15 0.21 | 1.18 1.53 1.52 1.07 1.32
Operating Costs 1.54 1.59 1.82 | 1.67 1.84 1.84 1.66 1.75
- -----------------------------------------------------------------------|--------------------------------------------------
Netback 2.62 1.68 0.82 | 4.72 6.30 4.64 3.33 4.66
- -----------------------------------------------------------------------|--------------------------------------------------
YEMEN |
Sales (mbbls/d) 54.7 51.4 43.2 | 62.5 57.4 54.2 51.7 56.4
|
Price Received ($/bbl) 52.30 69.40 76.31 | 96.57 120.39 115.92 64.48 99.87
Royalties & Other 19.43 31.94 32.08 | 48.07 59.21 52.47 26.33 46.94
Operating Costs 9.62 10.39 12.43 | 7.76 8.80 7.82 9.80 8.51
In-country Taxes 4.92 9.01 9.70 | 11.82 17.45 16.11 7.60 13.31
- -----------------------------------------------------------------------|--------------------------------------------------
Netback 18.33 18.06 22.10 | 28.92 34.93 39.52 20.75 31.11
- -----------------------------------------------------------------------|--------------------------------------------------
SYNCRUDE |
Sales (mbbls/d) 19.8 14.9 22.5 | 19.3 19.1 22.9 22.3 20.9
|
Price Received ($/bbl) 55.48 71.58 74.54 | 101.70 130.90 126.56 65.48 105.47
Royalties & Other 0.40 8.84 8.31 | 11.93 22.08 21.89 4.97 15.11
Operating Costs 36.95 57.21 29.50 | 35.16 45.09 32.40 34.67 36.53
- -----------------------------------------------------------------------|--------------------------------------------------
Netback 18.13 5.53 36.73 | 54.61 63.73 72.27 25.84 53.83
- -----------------------------------------------------------------------|--------------------------------------------------
(1) Defined as average sales price less royalties and other, operating costs,
and in-country taxes in Yemen.
11
NEXEN INC.
OIL AND GAS CASH NETBACK (1) (CONTINUED)
TOTAL
Quarters - 2009 Quarters - 2008 YEAR
--------------------------------|--------------------------------------|---------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd | 1st 2nd 3rd 4th | 2008
- -------------------------------------------------------------------------|--------------------------------------|---------
UNITED STATES
Crude Oil: |
Sales (mbbls/d) 10.4 12.1 9.5 | 13.7 11.3 8.5 3.8 9.3
Price Received ($/bbl) 46.27 66.23 72.27 | 94.07 120.77 122.46 58.43 104.94
Natural Gas: |
Sales (mmcf/d) 50 61 63 | 112 99 70 31 78
Price Received ($/mcf) 5.93 4.58 3.56 | 9.03 11.80 10.14 8.09 10.07
Total Sales Volume (mboe/d) 18.8 22.2 20.0 | 32.4 27.8 20.2 8.9 22.3
|
Price Received ($/boe) 41.50 48.53 45.43 | 71.10 91.08 86.75 52.77 79.02
Royalties & Other 4.52 4.94 4.77 | 9.53 12.88 12.30 7.89 11.03
Operating Costs 13.79 13.11 12.40 | 8.20 9.28 15.62 21.58 11.57
- -------------------------------------------------------------------------|------------------------------------------------
Netback 23.19 30.48 28.26 | 53.37 68.92 58.83 23.30 56.42
- -------------------------------------------------------------------------|------------------------------------------------
UNITED KINGDOM |
Crude Oil: |
Sales (mbbls/d) 100.8 97.0 70.4 | 108.9 89.0 107.0 96.4 100.3
Price Received ($/bbl) 51.60 69.42 73.15 | 93.38 118.24 114.89 58.60 96.23
Natural Gas: |
Sales (mmcf/d) 21 17 17 | 22 24 18 16 20
Price Received ($/mcf) 5.50 3.67 2.64 | 6.82 7.06 7.53 5.44 6.78
Total Sales Volume (mboe/d) 104.3 99.8 73.2 | 112.6 93.0 110.0 99.0 103.7
|
Price Received ($/boe) 50.97 68.10 70.95 | 91.67 114.95 112.99 57.91 94.45
Operating Costs 5.48 5.85 10.34 | 5.67 7.42 6.71 7.39 6.75
- -------------------------------------------------------------------------|------------------------------------------------
Netback 45.49 62.25 60.61 | 86.00 107.53 106.28 50.52 87.70
- -------------------------------------------------------------------------|------------------------------------------------
OTHER COUNTRIES |
Sales (mbbls/d) 5.5 3.6 2.6 | 6.0 5.7 5.7 5.8 5.8
|
Price Received ($/bbl) 41.68 66.83 70.49 | 91.85 113.18 120.11 72.43 98.98
Royalties & Other 3.26 5.17 5.38 | 7.46 8.95 9.42 5.81 7.88
Operating Costs 4.81 5.73 5.70 | 4.74 4.43 5.14 3.79 4.52
- -------------------------------------------------------------------------|------------------------------------------------
Netback 33.61 55.93 59.41 | 79.65 99.80 105.55 62.83 86.58
- -------------------------------------------------------------------------|------------------------------------------------
|
COMPANY-WIDE |
Oil and Gas Sales (mboe/d) 241.4 228.9 198.2 | 270.1 240.4 250.9 226.9 247.0
|
Price Received ($/boe) 47.56 61.28 63.00 | 85.90 108.26 106.22 56.94 89.78
Royalties & Other 5.64 9.23 9.58 | 14.87 19.92 16.98 8.22 15.06
Operating Costs 10.62 11.95 13.60 | 9.46 11.89 10.90 12.01 11.04
In-country Taxes 1.11 2.02 2.11 | 2.74 4.16 3.48 1.73 3.04
- -------------------------------------------------------------------------|------------------------------------------------
Netback 30.19 38.08 37.71 | 58.83 72.29 74.86 34.98 60.64
- -------------------------------------------------------------------------|------------------------------------------------
(1) Defined as average sales price less royalties and other, operating costs,
and in-country taxes in Yemen.
12
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions, except per share amounts) 2009 2008 2009 2008
- -----------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,097 2,213 3,345 6,154
Marketing and Other (Note 14) 296 131 635 387
----------------------------------------------
1,393 2,344 3,980 6,541
----------------------------------------------
EXPENSES
Operating 321 341 946 998
Depreciation, Depletion, Amortization and Impairment 358 386 1,180 1,084
Transportation and Other 185 291 618 691
General and Administrative 113 (308) 380 165
Exploration 89 112 219 245
Interest (Note 9) 84 16 226 59
----------------------------------------------
1,150 838 3,569 3,242
----------------------------------------------
INCOME BEFORE PROVISION FOR INCOME TAXES 243 1,506 411 3,299
----------------------------------------------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 190 (26) 514 817
Future (81) 645 (397) 583
----------------------------------------------
109 619 117 1,400
----------------------------------------------
NET INCOME 134 887 294 1,899
Less: Net Income Attributable to Canexus Non-Controlling Interests (12) (1) (17) (3)
----------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 122 886 277 1,896
==============================================
EARNINGS PER COMMON SHARE ($/share) (Note 15)
Basic 0.23 1.68 0.53 3.59
==============================================
Diluted 0.23 1.66 0.53 3.53
==============================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
13
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
September 30 December 31
(Cdn$ millions, except share amounts) 2009 2008
- --------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 1,897 2,003
Restricted Cash (Note 7) 216 103
Accounts Receivable (Note 2) 2,877 3,163
Inventories and Supplies (Note 3) 590 484
Other 199 169
------------------------------------
Total Current Assets 5,779 5,922
------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $10,452 (December 31, 2008 - $10,393) 15,642 14,922
GOODWILL 346 390
FUTURE INCOME TAX ASSETS 916 351
DEFERRED CHARGES AND OTHER ASSETS (Note 5) 386 570
------------------------------------
TOTAL ASSETS 23,069 22,155
====================================
LIABILITIES
CURRENT LIABILITIES
Accounts Payable and Accrued Liabilities (Note 8) 3,358 3,326
Accrued Interest Payable 81 67
Dividends Payable 26 26
------------------------------------
Total Current Liabilities 3,465 3,419
------------------------------------
LONG-TERM DEBT (Note 9) 7,429 6,578
FUTURE INCOME TAX LIABILITIES 2,698 2,619
ASSET RETIREMENT OBLIGATIONS (Note 11) 992 1,024
DEFERRED CREDITS AND OTHER LIABILITIES (Note 12) 1,084 1,324
SHAREHOLDERS' EQUITY (Note 13)
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2009 - 521,846,559 shares
2008 - 519,448,590 shares 1,025 981
Contributed Surplus 1 2
Retained Earnings 6,489 6,290
Accumulated Other Comprehensive Loss (183) (134)
------------------------------------
Total Nexen Inc. Shareholders' Equity 7,332 7,139
Canexus Non-Controlling Interests 69 52
------------------------------------
TOTAL SHAREHOLDERS' EQUITY 7,401 7,191
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16)
------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 23,069 22,155
====================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
14
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
- ---------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income 134 887 294 1,899
Charges and Credits to Income not Involving Cash (Note 17) 174 692 887 1,544
Exploration Expense 89 112 219 245
Changes in Non-Cash Working Capital (Note 17) 113 (840) 193 (468)
Other (49) 117 (234) 79
------------------------------------------------
461 968 1,359 3,299
FINANCING ACTIVITIES
Proceeds from Long-Term Notes 1,081 - 1,081 -
Proceeds from (Repayment of) Term Credit Facilities, Net (915) 1,031 728 803
Proceeds from (Repayment of) Canexus Term Credit Facilities, Net (4) (9) 48 (19)
Proceeds from Canexus Debentures 46 - 46 -
Proceeds from Canexus Notes - - - 51
Repayment of Medium-Term Notes - - - (125)
Repayment of Short-Term Borrowings (1) (4) (1) (4)
Dividends on Common Shares (26) (26) (78) (66)
Distributions Paid to Canexus Non-Controlling Interests (4) (4) (11) (11)
Issue of Common Shares and Exercise of Tandem Options for Shares 12 8 42 48
Repurchase of Common Shares for Cancellation - (300) - (300)
Changes in Non-Cash Working Capital (Note 17) - 10 - 10
Other (18) 2 (19) -
------------------------------------------------
171 708 1,836 387
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (586) (689) (1,921) (2,064)
Proved Property Acquisitions - - (755) (2)
Energy Marketing, Chemicals, Corporate and Other (69) (36) (198) (83)
Proceeds on Disposition of Assets 2 - 17 -
Changes in Restricted Cash 93 196 (154) 143
Changes in Non-Cash Working Capital (Note 17) 14 (66) (41) (120)
Other (15) 36 (16) (61)
------------------------------------------------
(561) (559) (3,068) (2,187)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (148) 41 (233) 67
------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (77) 1,158 (106) 1,566
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 1,974 614 2,003 206
------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD (1) 1,897 1,772 1,897 1,772
================================================
(1) Cash and cash equivalents at September 30, 2009 consist of cash of $376
million and short-term investments of $1,521 million (September 30, 2008 -
cash of $26 million and short-term investments of $1,746 million).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
15
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
- ---------------------------------------------------------------------------------------------------------------------------
COMMON SHARES, Beginning of Period 1,011 972 981 917
Issue of Common Shares 8 8 37 32
Exercise of Tandem Options for Shares 4 - 5 16
Accrued Liability Relating to Tandem Options Exercised for Common
Shares 2 1 2 16
Repurchased Under Normal Course Issuer Bid - (18) - (18)
----------------------------------------------
Balance at End of Period 1,025 963 1,025 963
==============================================
CONTRIBUTED SURPLUS, Beginning of Period 2 2 2 3
Exercise of Tandem Options (1) - (1) (1)
----------------------------------------------
Balance at End of Period 1 2 1 2
==============================================
RETAINED EARNINGS, Beginning of Period 6,393 5,953 6,290 4,983
Net Income Attributable to Nexen Inc. 122 886 277 1,896
Dividends on Common Shares (Note 13) (26) (26) (78) (66)
Repurchase of Common Shares for Cancellation - (282) - (282)
----------------------------------------------
Balance at End of Period 6,489 6,531 6,489 6,531
----------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE LOSS, Beginning of Period (157) (274) (134) (293)
Other Comprehensive Income (Loss) (26) 41 (49) 60
----------------------------------------------
Balance at End of Period (183) (233) (183) (233)
==============================================
CANEXUS NON-CONTROLLING INTERESTS, Beginning of Period 54 62 52 67
Net Income Attributable to Non-Controlling Interests 15 1 24 3
Distributions Declared to Non-Controlling Interests (5) (5) (14) (13)
Issue of Partnership Units to Non-Controlling Interests under
Distribution Reinvestment Plan 1 1 3 2
Estimated Fair Value of Conversion Feature of Convertible Debenture
Issue Attributable to Non-Controlling Interests 4 - 4 -
----------------------------------------------
Balance at End of Period 69 59 69 59
==============================================
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 122 886 277 1,896
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment
Net Gains (Losses) on Investment in Self-Sustaining Foreign
Operations (408) 221 (693) 365
Net Gains (Losses) on Foreign-Denominated Debt Hedging Self-
Sustaining Foreign Operations(1) 384 (180) 646 (305)
Realized Translation Adjustments Recognized in Net Income (2) - (2) -
----------------------------------------------
Other Comprehensive Income (Loss) (26) 41 (49) 60
----------------------------------------------
COMPREHENSIVE INCOME ATTRIBUTABLE TO NEXEN INC. 96 927 228 1,956
==============================================
(1) Net of income tax expense for the three months ended September 30, 2009 of
$55 million (2008 - $26 million recovery) and net of income tax expense for
the nine months ended September 30, 2009 of $93 million (2008 - $45 million
recovery).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
16
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions, except as noted
1. ACCOUNTING POLICIES
Our Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The impact of
significant differences between Canadian and United States GAAP on the Unaudited
Consolidated Financial Statements is disclosed in Note 19. In the opinion of
management, the Unaudited Consolidated Financial Statements contain all
adjustments of a normal and recurring nature necessary to present fairly Nexen
Inc.'s (Nexen, we or our) financial position at September 30, 2009 and December
31, 2008 and the results of our operations and our cash flows for the three and
nine months ended September 30, 2009 and 2008.
We make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the Unaudited Consolidated Financial Statements, and revenues and expenses
during the reporting period. Our management reviews these estimates on an
ongoing basis, including those related to accruals, litigation, environmental
and asset retirement obligations, recoverability of assets, income taxes, fair
values of derivative assets and liabilities, capital adequacy and determination
of proved reserves. Changes in facts and circumstances may result in revised
estimates and actual results may differ from these estimates. The results of
operations and cash flows for the three and nine months ended September 30, 2009
are not necessarily indicative of the results of operations or cash flows to be
expected for the year ending December 31, 2009. As at October 27, 2009, there
are no material subsequent events requiring additional disclosure in or
amendment to these financial statements.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2008 Form
10-K. Except as described below, the accounting policies we follow are described
in Note 1 of the Audited Consolidated Financial Statements included in our 2008
Form 10-K.
CHANGES IN ACCOUNTING POLICIES
GOODWILL AND INTANGIBLE ASSETS
On January 1, 2009, we retrospectively adopted the Canadian Institute of
Chartered Accountants (CICA) Section 3064, GOODWILL AND INTANGIBLE ASSETS issued
by the AcSB. This section clarifies the criteria for the recognition of assets,
intangible assets and internally developed intangible assets. Adoption of this
standard did not have a material impact on our results of operations or
financial position.
BUSINESS COMBINATIONS
On January 1, 2009, we prospectively adopted CICA Section 1582, BUSINESS
COMBINATIONS issued by the AcSB. This section establishes principles and
requirements of the acquisition method for business combinations and related
disclosures. Adoption of this statement did not have a material impact on our
results of operations or financial position.
CONSOLIDATED FINANCIAL STATEMENTS AND NON-CONTROLLING INTERESTS
On January 1, 2009, we adopted CICA Sections 1601, CONSOLIDATED FINANCIAL
STATEMENTS, and 1602, NON-CONTROLLING INTERESTS issued by the AcSB. Section 1601
establishes standards for the preparation of consolidated financial statements.
Section 1602 provides guidance on accounting for non-controlling interests in
consolidated financial statements subsequent to a business combination. Adoption
of these statements did not have a material impact on our results of operations
or financial position. The presentation changes have been included in the
Unaudited Consolidated Financial Statements as applicable.
2. ACCOUNTS RECEIVABLE
September 30 December 31
2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
Trade
Energy Marketing 1,489 1,501
Energy Marketing Derivative Contracts (Note 6) 552 755
Oil and Gas 657 639
Chemicals and Other 47 68
------------------------------------------
2,745 2,963
Non-Trade 186 270
------------------------------------------
2,931 3,233
Allowance for Doubtful Receivables (54) (70)
------------------------------------------
Total 2,877 3,163
==========================================
17
3. INVENTORIES AND SUPPLIES
September 30 December 31
2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
Finished Products
Energy Marketing 449 384
Oil and Gas 32 17
Chemicals and Other 11 16
------------------------------------------
492 417
Work in Process 8 6
Field Supplies 90 61
------------------------------------------
Total 590 484
==========================================
4. SUSPENDED EXPLORATION WELL COSTS
The following table shows the changes in capitalized exploratory well costs
during the nine months ended September 30, 2009 and the year ended December 31,
2008, and does not include amounts that were initially capitalized and
subsequently expensed in the same period. Suspended exploration well costs are
included in property, plant and equipment.
Nine Months Ended Year Ended
September 30 December 31
2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
Beginning of Period 518 326
Exploratory Well Costs Capitalized Pending the Determination of
Proved Reserves 186 254
Capitalized Exploratory Well Costs Charged to Expense (32) (81)
Transfers to Wells, Facilities and Equipment Based on
Determination of Proved Reserves (17) (29)
Effects of Foreign Exchange Rate Changes (37) 48
------------------------------------------
End of Period 618 518
==========================================
The following table provides an aging of capitalized exploratory well costs
based on the date drilling was completed and shows the number of projects for
which exploratory well costs have been capitalized for a period greater than one
year after the completion of drilling.
September 30 December 31
2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 189 239
Capitalized for a Period of Greater than One Year 429 279
------------------------------------------
Total 618 518
==========================================
Number of Projects that have Exploratory Well Costs Capitalized for a Period
Greater than One Year 11 7
------------------------------------------
As at September 30, 2009, we have exploratory costs that have been capitalized
for more than one year relating to our interests in six exploratory blocks in
the North Sea ($178 million), certain coalbed methane and shale gas exploratory
activities in Canada ($120 million), two exploratory blocks in the Gulf of
Mexico ($112 million), and our interest in an exploratory block offshore Nigeria
($19 million). These costs relate to projects with successful exploration wells
for which we have not been able to recognize proved reserves. We are assessing
all of these wells and projects, and are working with our partners to prepare
development plans, drill additional appraisal wells or to assess commercial
viability.
18
5. DEFERRED CHARGES AND OTHER ASSETS
September 30 December 31
2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
Crude Oil Put Options and Natural Gas Swaps (Note 6) (1) - 234
Long-Term Energy Marketing Derivative Contracts (Note 6) 241 217
Long-Term Capital Prepayments 42 61
Asset Retirement Remediation Fund 9 9
Defined Benefit Pension Assets 46 3
Other 48 46
------------------------------------------
Total 386 570
==========================================
(1) The crude oil put options were reclassified to other current assets in the
first quarter as they settle within 12 months.
6. FINANCIAL INSTRUMENTS
Financial instruments carried at fair value on our balance sheet include cash
and cash equivalents, restricted cash and derivatives used for trading and
non-trading purposes. Our other financial instruments, including accounts
receivable, accounts payable, accrued interest payable, dividends payable,
short-term borrowings and long-term debt, are carried at cost or amortized cost.
The carrying values of our short-term receivables and payables approximate their
fair value as the instruments are near maturity.
In our energy marketing group, we enter into contracts to purchase and sell
crude oil, natural gas and other energy commodities, and use derivative
contracts, including futures, forwards, swaps and options, for hedging and
trading purposes (collectively derivatives). We also use derivatives to manage
commodity price risk and foreign currency risk for non-trading purposes. We
categorize our derivative instruments as trading or non-trading activities and
carry the instruments at fair value on our balance sheet. The derivatives
section below details our derivatives and fair values as at September 30, 2009.
The fair values are included with accounts receivable or payable and are
classified as long-term or short-term based on anticipated settlement date. Any
change in fair value is included in marketing and other income.
We carry our long-term debt at amortized cost using the effective interest rate
method. At September 30, 2009, the estimated fair value of our long-term debt
was $7,531 million (December 31, 2008 - $5,686 million) as compared to the
carrying value of $7,429 million (December 31, 2008 - $6,578 million). The fair
value of long-term debt is estimated based on prices provided by quoted markets
and third-party brokers.
19
DERIVATIVES
(a) DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES
Our energy marketing group engages in various activities including the purchase
and sale of physical commodities and the use of financial instruments such as
commodity and foreign exchange futures, forwards and swaps to economically hedge
exposures and generate revenue. These contracts are accounted for as derivatives
and, where applicable, are presented net on the balance sheet in accordance with
netting arrangements. The fair value and carrying amounts related to derivative
instruments held by our energy marketing operations are as follows:
September 30 December 31
2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Commodity Contracts 537 742
Foreign Exchange Contracts 15 13
------------------------------------------
Accounts Receivable (Note 2) 552 755
------------------------------------------
Commodity Contracts 241 213
Foreign Exchange Contracts - 4
------------------------------------------
Deferred Charges and Other Assets (Note 5) (1) 241 217
------------------------------------------
Total Trading Derivative Assets 793 972
==========================================
Commodity Contracts 516 585
Foreign Exchange Contracts 56 30
------------------------------------------
Accounts Payable and Accrued Liabilities (Note 8) 572 615
------------------------------------------
Commodity Contracts 228 248
Foreign Exchange Contracts - 46
------------------------------------------
Deferred Credits and Other Liabilities (Note 12) (1) 228 294
------------------------------------------
Total Trading Derivative Liabilities 800 909
==========================================
Total Net Trading Derivative Contracts (7) 63
==========================================
(1) These derivative contracts settle beyond 12 months and are considered
non-current; once settlement is within 12 months, they are included in
accounts receivable or accounts payable.
Excluding the impact of netting arrangements, the fair value of derivative
instruments is as follows:
September 30
2009
- -----------------------------------------------------------------------------------------------------------------------------
Current Trading Assets 3,608
Non-Current Trading Assets 1,031
---------------------
Total Trading Derivative Assets 4,639
=====================
Current Trading Liabilities 3,628
Non-Current Trading Liabilities 1,018
---------------------
Total Trading Derivative Liabilities 4,646
=====================
---------------------
Total Net Trading Derivative Contracts (7)
=====================
Trading revenues generated by our energy marketing group include gains and
losses on derivative instruments and non-derivative instruments such as physical
inventory. During the three and nine months ended September 30, 2009, the
following trading revenues were recognized in marketing and other income:
Three Months Nine Months
Ended September 30 Ended September 30
2009 2009
- ------------------------------------------------------------------------------------------------------------------------------
Commodity 177 748
Foreign Exchange 11 (72)
--------------------- ----------------------
Marketing Revenue (Note 14) 188 676
===================== ======================
20
As an energy marketer, we may undertake several transactions during a period to
execute a single sale of physical product. Each transaction may be represented
by one or more derivative instruments including a physical buy, physical sell,
and in many cases, numerous financial instruments for economically hedging and
trading purposes. The absolute notional volumes associated with our derivative
instrument transactions are as follows:
Three Months Nine Months
Ended September 30 Ended September 30
2009 2009
- -----------------------------------------------------------------------------------------------------------------------------
Natural Gas bcf/d 19.3 22.2
Crude Oil mmbbls/d 3.1 3.6
Power GWh/d 236.1 231.0
Foreign Exchange USD millions 742 1,973
Foreign Exchange Euro millions 48 308
-----------------------------------------------
(b) DERIVATIVE CONTRACTS RELATED TO NON-TRADING ACTIVITIES
The fair value and carrying amounts of derivative instruments related to
non-trading activities are as follows:
September 30 December 31
2009 2008
- ------------------------------------------------------------------------------------------------------------------------------
Accounts Receivable 12 6
Deferred Charges and Other Assets (Note 5) (1) - 234
--------------------------------------------
Total Non-Trading Derivative Assets 12 240
============================================
Accounts Payable and Accrued Liabilities 27 21
Deferred Credits and Other Liabilities (1) 7 26
--------------------------------------------
Total Non-Trading Derivative Liabilities 34 47
============================================
Total Net Non-Trading Derivative Contracts (2) (22) 193
============================================
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) The net fair value of these derivatives is equal to the gross fair value
before consideration of netting arrangements and collateral posted or
received with counterparties.
CRUDE OIL PUT OPTIONS
In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009
crude oil production for $14 million. These options establish an annual average
Dated Brent floor price of US$60/bbl on these volumes. In September 2008, Lehman
Brothers filed for bankruptcy protection. This impacts approximately 25,000
bbls/d of our 2009 put options and the carrying value of these put options has
been reduced to nil. The crude oil put options are carried at fair value and are
classified as long-term or short-term based on their anticipated settlement
date. Fair value of the put options is supported by multiple quotes obtained
from third party brokers, which were validated with observable market data to
the extent possible. With the rise in Dated Brent oil price since the beginning
of the year, the fair value of the crude oil put options decreased. This
decrease is included in marketing and other income.
Change in Fair Value
-----------------------------------
Three Months Nine Months
Ended Ended
Notional Average Fair September 30 September 30
Volumes Term Floor Price Value 2009 2009
- -------------------------------------------------------------------------------------------------------------------------------
(bbls/d) (US$/bbl)
Dated Brent Crude Oil Put Options 45,000 2009 60 12 (23) (218)
Dated Brent Crude Oil Put Options 25,000 2009 60 - - -
-------------------------------------------------
12 (23) (218)
=================================================
21
FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS
We have fixed-price natural gas sales contracts and offsetting natural gas swaps
that are not part of our trading activities. These sales contracts and swaps are
carried at fair value and are classified as long-term or short-term based on
their anticipated settlement date. The change in fair value of the fixed price
natural gas contracts and natural gas swaps is included in marketing and other
income.
Change in Fair Value
-----------------------------------
Three Months Nine Months
Ended Ended
Notional Average Fair September 30 September 30
Volumes Term Price Value 2009 2009
- -------------------------------------------------------------------------------------------------------------------------------
(Gj/d) ($/Gj)
Fixed-Price Natural Gas Contracts 15,514 2009 2.28 (14) (2) 7
15,514 2010 2.28 (5) 4 21
Natural Gas Swaps 15,514 2009 7.60 (13) 3 (19)
15,514 2010 7.60 (2) 2 (3)
----------------------------------------------
(34) 7 6
==============================================
(c) FAIR VALUE OF DERIVATIVES
Our processes for estimating and classifying the fair value of our derivative
contracts are consistent with those in place at December 31, 2008. The following
table includes our derivatives carried at fair value for our trading and
non-trading activities as at September 30, 2009. Financial assets and
liabilities are classified in the fair value hierarchy in their entirety based
on the lowest level of input that is significant to the fair value measurement.
Assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect placement within the fair value
hierarchy levels.
Net Derivatives Level 1 Level 2 Level 3 Total
- ------------------------------------------------------------------------------------------------------------------------------
Trading Derivatives (180) 151 22 (7)
Non-Trading Derivatives - (22) - (22)
---------------------------------------------------------
Total (180) 129 22 (29)
=========================================================
A reconciliation of changes in the fair value of our derivatives classified as
Level 3 for the nine months ended September 30, 2009 is provided below:
Level 3
- ------------------------------------------------------------------------------------------------------------------------------
Beginning of Period (82)
Realized and Unrealized Gains (Losses) 57
Purchases, Issuances and Settlements 55
Transfers In and/or Out of Level 3 (8)
---------------
End of Period 22
===============
Unsettled Gains (Losses) Relating to Instruments Still Held as of September 30, 2009 49
===============
Trading derivatives classified in Level 3 are generally economically hedged such
that gains or losses on positions classified in Level 3 are often offset by
gains or losses on positions classified in Level 1 or 2. Transfers into or out
of Level 3 represent existing assets and liabilities that were either previously
categorized as a higher level for which the inputs became unobservable or assets
and liabilities that were previously classified as Level 3 for which the lowest
significant input became observable during the period.
7. RISK MANAGEMENT
(a) MARKET RISK
We invest in significant capital projects, purchase and sell commodities, issue
short-term borrowings and long-term debt, and invest in foreign operations.
These activities expose us to market risks from changes in commodity prices,
foreign exchange rates and interest rates, which affect our earnings and the
value of the financial instruments we hold. We use derivatives for trading and
non-trading purposes as part of our overall risk management policy to manage
these market exposures.
The following market risk discussion focuses on the commodity price risk and
foreign currency risk related to our financial instruments as our exposure to
interest rate risk is immaterial as substantially all of our debt is fixed rate.
22
COMMODITY PRICE RISK
We are exposed to commodity price movements as part of our normal oil and gas
operations, particularly in relation to the prices received for our crude oil
and natural gas. Commodity price risk related to conventional and synthetic
crude oil prices is our most significant market risk exposure. Crude oil and
natural gas are sensitive to numerous worldwide factors and are generally sold
at contract or posted prices. Changes in the global supply and demand
fundamentals in the crude oil market and geopolitical events can significantly
affect crude oil prices, while natural gas prices are affected primarily by
North American supply and demand fundamentals. Changes in crude oil and natural
gas prices may significantly affect our results of operations and cash generated
from operating activities. Consequently, these changes may also affect the value
of our oil and gas properties, our level of spending for exploration and
development, and our ability to meet our obligations as they come due.
The majority of our oil and gas production is sold under short-term contracts,
exposing us to the risk of price movements. Other energy contracts also expose
us to commodity price risk during the time between when we purchase and sell
contracted volumes. We periodically manage these risks by using derivative
contracts such as commodity put options.
Our energy marketing business is focused on providing services for our customers
and suppliers to meet their energy commodity needs. We market and trade physical
energy commodities including crude oil, natural gas, electricity and other
commodities in selected regions of the world. We accomplish this by buying and
selling physical commodities, by acquiring and holding rights to physical
transportation and storage assets for these commodities, and by building strong
relationships with our customers and suppliers. In order to manage the commodity
and foreign exchange price risks that are generated by this physical business,
we use financial derivative contracts including energy-related futures,
forwards, swaps and options, as well as foreign currency swaps or forwards.
We also seek to profit from our views on the future movement of energy commodity
pricing relationships, primarily between different locations, time periods or
product qualities. We do this by holding open positions, where the terms of
physical or financial contracts are not completely matched to offsetting
positions. We may also carry exposures to the absolute change in commodity
prices based on our market views or as a consequence of managing our physical
and financial positions on a daily basis.
Our risk management activities include prescribed capital limits and the use of
tools such as Value-at-Risk (VaR) and stress testing consistent with the
methodology used at December 31, 2008. Our period end, high, low and average VaR
amounts for the three and nine months ended September 30, 2009 are as follows:
Three Months Nine Months
Ended September 30 Ended September 30
Value-at-Risk 2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Period End 13 27 13 27
High 15 33 24 40
Low 11 19 11 19
Average 12 29 16 31
---------------------------------------------------
If market shocks occur in 2009 as they did in 2008, the key assumptions
underlying our VaR estimate could be exceeded and the potential loss could be
greater than our estimate. We perform stress tests on a regular basis to
complement VaR and assess the impact of non-normal changes in prices on our
positions.
FOREIGN CURRENCY RISK
Foreign currency risk is created by fluctuations in the fair values or cash
flows of financial instruments due to changes in foreign exchange rates. A
substantial portion of our activities are transacted in or referenced to US
dollars including:
o sales of crude oil, natural gas and certain chemicals products;
o capital spending and expenses for our oil and gas, Syncrude and chemicals
operations;
o commodity derivative contracts used primarily by our energy marketing
group; and
o short-term borrowings and long-term debt.
In our oil and gas operations, we manage our exposure to fluctuations between
the US and Canadian dollar by matching our expected net cash flows and
borrowings in the same currency. Net revenue from our foreign operations and our
US-dollar borrowings are generally used to fund US-dollar capital expenditures
and debt repayments. We maintain revolving Canadian and US-dollar borrowing
facilities that can be used or repaid depending on expected cash flows. We
designate a portion of our US-dollar borrowings as a hedge against our US-dollar
net investment in self-sustaining foreign operations.
23
The foreign exchange gains or losses related to the effective portion of our
designated US-dollar debt are included in accumulated other comprehensive income
in shareholders' equity. Our net investment in self-sustaining foreign
operations and our designated US-dollar debt at September 30, 2009 and December
31, 2008 are as follows:
September 30 December 31
(US$ millions) 2009 2008
- ------------------------------------------------------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations 4,272 4,662
Designated US-Dollar Debt 4,272 4,545
-------------------------------------------
For the three and nine month periods ended September 30, 2009, the ineffective
portion of our US-dollar debt resulted in a net foreign exchange gain of $78
million and $135 million, respectively ($68 million and $118 million,
respectively, net of income tax expense) and is included in marketing and other
income. A one cent change in the US dollar to Canadian dollar exchange rate
would increase or decrease our accumulated other comprehensive income by
approximately $43 million, net of income tax, and would increase or decrease our
net income by approximately $8 million, net of income tax.
We also have modest exposures to currencies other than the US dollar including a
portion of our UK operating expenses, capital spending and future asset
retirement obligations which are denominated in British Pounds and Euros. We do
not have any material exposure to highly inflationary foreign currencies. In our
energy marketing group, we enter into transactions in various currencies
including Canadian and US dollars, British Pounds and Euros. We may actively
manage significant currency exposures using forward contracts and swaps.
(b) CREDIT RISK
Credit risk affects our oil, gas and chemicals operations and trading and
non-trading derivative activities is the risk of loss if counterparties do not
fulfill their contractual obligations. Most of our credit exposure is with
counterparties in the energy industry, including integrated oil companies, crude
oil refiners and utilities, and are subject to normal industry credit risk.
Approximately 74% of our exposure is with these large energy companies. This
concentration of risk within the energy industry is reduced because of our broad
base of domestic and international counterparties. Our processes to manage this
risk are consistent with those in place at December 31, 2008.
At September 30, 2009, only one counterparty individually made up more than 10%
of our credit exposure. This counterparty is a major integrated oil company with
a strong investment grade credit rating. No other counterparties made up more
than 5% of our credit exposure. The following table illustrates the composition
of credit exposure by credit rating.
September 30 December 31
CREDIT RATING 2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
A or higher 71% 65%
BBB 22% 29%
Non-Investment Grade 7% 6%
------------------------------------------
TOTAL 100% 100%
==========================================
Our maximum counterparty credit exposure at the balance sheet date consists
primarily of the carrying amounts on non-derivative financial assets such as
cash and cash equivalents, restricted cash, accounts receivable, as well as the
fair value of derivative financial assets. We provided an allowance of $54
million for credit risk with our counterparties. In addition, we incorporate the
credit risk associated with counterparty default, as well as Nexen's own credit
risk, into our estimates of fair value.
Collateral received from customers at September 30, 2009 includes $51 million of
cash and $506 million of letters of credit. The cash received reflects customer
deposits that are included in accounts payable and accrued liabilities.
(c) LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial
obligations as they become due. We require liquidity specifically to fund
capital requirements, satisfy financial obligations as they become due, and to
operate our energy marketing business. We generally rely on operating cash flows
to provide liquidity and we also maintain significant undrawn committed credit
facilities. At September 30, 2009, we had approximately $3.2 billion of cash and
available committed lines of credit. This includes $1.9 billion of cash and cash
equivalents on hand. In addition, we have undrawn term credit facilities of $1.7
billion, of which $427 million was supporting letters of credit at September 30,
2009. These facilities are available until 2012. We also have about $493 million
of undrawn, uncommitted credit facilities at September 30, 2009.
24
The following table details the contractual maturities for our non-derivative
financial liabilities, including both the principal and interest cash flows at
September 30, 2009:
less than more than
Total 1 Year 1-3 Years 4-5 Years 5 Years
- ------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (1) 7,522 - 1,847 590 5,085
Interest on Long-Term Debt (2) 8,340 369 739 712 6,520
---------------------------------------------------------------------------------------
Total 15,862 369 2,586 1,302 11,605
=======================================================================================
(1) Excludes cash and cash equivalents currently available.
(2) Excludes interest on term credit facilities of $3.3 billion and Canexus
term credit facilities of $452 million as the amounts drawn on the
facilities fluctuate. Based on amounts drawn at September 30, 2009 and
current interest rates, we would be required to pay $20 million per year
until the outstanding amounts on the term credit facilities are repaid.
The following table details contractual maturities for our derivative financial
liabilities. The balance sheet amounts for derivative financial liabilities
included below are not materially different from the contractual amounts due on
maturity.
less than more than
Total 1 Year 1-3 Years 4-5 Years 5 Years
- ------------------------------------------------------------------------------------------------------------------------------
Trading Derivatives (Note 6) 800 572 189 39 -
Non-Trading Derivatives (Note 6) 34 27 7 - -
---------------------------------------------------------------------------------------
Total 834 599 196 39 -
=======================================================================================
The commercial agreements our energy marketing group enter into often include
financial assurance provisions that allow us and our counterparties to
effectively manage credit risk. The agreements normally require collateral to be
posted if an adverse credit-related event occurs, such as a drop in credit
rating. Based on contracts in place and commodity prices at September 30, 2009,
we could be required to post collateral of up to $975 million if we were
downgraded to non-investment grade. This represents the maximum amount of
collateral that we would be required to post assuming a severe event that causes
all rating agencies to simultaneously downgrade us and no actions are taken by
us to mitigate our exposure. This amount includes trade payables of $686 million
and derivative contracts with a fair value of $289 million. All of these
obligations are included on our September 30, 2009 balance sheet. In the event
of a ratings downgrade, we could monetize our trading inventories and
receivables and draw on our existing credit facilities to meet our collateral
obligations. Further various actions can be taken, in anticipation of a
downgrade that would reduce the maximum amount of collateral we would need to
provide.
At September 30, 2009, collateral posted with counterparties includes $14
million of cash and $330 million of letters of credit related to our trading
activities. Cash posted is included with our accounts receivable. Cash
collateral is not normally applied to contract settlement. Once a contract has
been settled, the collateral amounts are refunded. If there is a default, the
cash is retained. Our exchange-traded derivative contracts are also subject to
margin requirements. We have margin deposits of $216 million (December 31, 2008
- - $103 million), which have been included in restricted cash.
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
September 30 December 31
2009 2008
- -----------------------------------------------------------------------------------------------------------------------------
Energy Marketing 1,437 1,286
Accrued Payables 699 887
Energy Marketing Derivative Contracts (Note 6) 572 615
Income Taxes Payable 209 69
Trade Payables 208 251
Stock-Based Compensation 109 97
Other 124 121
------------------------------------------
Total 3,358 3,326
==========================================
25
9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
September 30 December 31
2009 2008
- ------------------------------------------------------------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2011 (US$223 million drawn) (a) 239 223
Term Credit Facilities, due 2012 (US$1.5 billion drawn) (b) 1,608 1,225
Canexus Notes, due 2013 (US$50 million) 54 61
Notes, due 2013 (US$500 million) 536 612
Canexus Convertible Debentures, due 2014 (c) 46 -
Notes, due 2015 (US$250 million) 268 306
Notes, due 2017 (US$250 million) 268 306
Notes, due 2019 (US$300 million) (d) 322 -
Notes, due 2028 (US$200 million) 214 245
Notes, due 2032 (US$500 million) 536 612
Notes, due 2035 (US$790 million) 847 968
Notes, due 2037 (US$1,250 million) 1,340 1,531
Notes, due 2039 (US$700 million) (e) 751 -
Subordinated Debentures, due 2043 (US$460 million) 493 563
-------------------------------------------
7,522 6,652
Unamortized Debt Issue Costs (93) (74)
-------------------------------------------
Total 7,429 6,578
===========================================
(a) CANEXUS TERM CREDIT FACILITIES
Canexus has $452 million (US$422 million) of committed, secured term credit
facilities, $431 million (US$402 million) of which is available until 2011, with
the balance due 2013. At September 30, 2009, $239 million (US$223 million) was
drawn on these facilities (December 31, 2008 - $223 million (US$182 million)).
Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans,
Canadian prime rate loans or US-dollar base rate loans. Interest is payable
monthly at floating rates. The term credit facilities are secured by a floating
charge debenture over all of Canexus' assets. The credit facility also contains
covenants with respect to certain financial ratios of Canexus. The
weighted-average interest rate on the Canexus term credit facilities was 2.0%
for the three months ended September 30, 2009 (three months ended September 30,
2008 - 4.6%) and 2.3% for the nine months ended September 30, 2009 (nine months
ended September 30, 2008 - 4.5%).
(b) TERM CREDIT FACILITIES
We have unsecured term credit facilities of $3.3 billion (US$3.1 billion)
available until 2012. At September 30, 2009, $1.6 billion (US$1.5 billion) was
drawn on these facilities (December 31, 2008 - $1.2 billion (US$1 billion)).
Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans,
Canadian prime rate loans, US-dollar base rate loans or British pound call-rate
loans. Interest is payable at floating rates. The weighted-average interest rate
on our term credit facilities was 0.9% for the three months ended September 30,
2009 (three months ended September 30, 2008 - 3.5%) and 1.0% for the nine months
ended September 30, 2009 (nine months ended September 30, 2008 - 3.6%). At
September 30, 2009, $427 million (US$398 million) of these facilities were
utilized to support outstanding letters of credit (December 31, 2008 - $381
million (US$311 million)).
(c) CANEXUS CONVERTIBLE DEBENTURES
In August 2009, Canexus issued $46 million of convertible unsecured subordinated
debentures to non-controlling interests. Interest is payable semi-annually at a
rate of 8.00%. These debentures mature on December 31, 2014 and are convertible
at the holder's option at any time prior to the close of business on the earlier
of i) the maturity date and ii) the business day immediately preceding the date
specified by Canexus for redemption of the debentures into trust units. The
conversion price is $5.10 per trust unit.
Canexus has the option to redeem the debentures in whole or in part from time to
time subject to the satisfaction of certain conditions, after December 31, 2012
but before maturity, at a redemption price equal to the principal amount and
unpaid interest. Canexus may elect to satisfy its obligation to pay interest or
repay the principal by issuing trust units at market value.
The estimated fair value of the conversion feature of the convertible debentures
amounted to $4 million and was included in non-controlling interests, in
shareholders' equity. The amount of the convertible debentures allocated to
long-term debt is being amortized over the term of the debt using the effective
interest rate method.
26
Concurrent with the issuance, we acquired $40 million of debentures from Canexus
with substantially the same terms which allow us to protect against dilution of
our ownership interest at our option. These debentures are eliminated on
consolidation.
(d) NOTES, DUE 2019
In July 2009, we issued US$300 million of notes. Interest is payable
semi-annually at a rate of 6.20%, and the principal is to be repaid in July
2019. We may redeem part or all of the notes at any time. The redemption price
will be the greater of par and an amount that provides the same yield as a US
Treasury security having a term-to-maturity equal to the remaining term of the
notes plus 0.40%.
(e) NOTES, DUE 2039
In July 2009, we issued US$700 million of notes. Interest is payable
semi-annually at a rate of 7.50%, and the principal is to be repaid in July
2039. We may redeem part or all of the notes at any time. The redemption price
will be the greater of par and an amount that provides the same yield as a US
Treasury security having a term-to-maturity equal to the remaining term of the
notes plus 0.45%.
(f) INTEREST EXPENSE
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Long-Term Debt 96 75 274 220
Other 4 5 12 15
---------------------------------------------------
Total 100 80 286 235
Less: Capitalized (16) (64) (60) (176)
---------------------------------------------------
Total 84 16 226 59
===================================================
Capitalized interest relates to and is included as part of the cost of our oil
and gas and Syncrude properties. The capitalization rates are based on our
weighted-average cost of borrowings.
(g) SHORT-TERM BORROWINGS
Nexen has uncommitted, unsecured credit facilities of approximately $493 million
(US$459 million), none of which were drawn at September 30, 2009 (December 31,
2008 - nil). We utilized $119 million (US$111 million) of these facilities to
support outstanding letters of credit at September 30, 2009 (December 31, 2008 -
$29 million (US$24 million)). Interest is payable at floating rates. The
weighted-average interest rate on our short-term borrowings was nil for the
three months ended September 30, 2009 (three months ended September 30, 2008 -
3.6%) and 2.1% for the nine months ended September 30, 2009 (nine months ended
September 30, 2008 - 3.2%).
10. CAPITAL MANAGEMENT
Our objectives and processes for managing our capital structure are consistent
with those in place at December 31, 2008. Our capital consists of shareholders'
equity, short-term borrowings, long-term debt and cash and cash equivalents as
follows:
September 30 December 31
2009 2008
- ------------------------------------------------------------------------------------------------------------------------------
NET DEBT (1)
Long-Term Debt 7,429 6,578
Less: Cash and Cash Equivalents (1,897) (2,003)
------------------------------------
Total 5,532 4,575
====================================
SHAREHOLDERS' EQUITY 7,401 7,191
====================================
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
We monitor the leverage in our capital structure by reviewing the ratio of net
debt to cash flow from operating activities and interest coverage ratios at
various commodity prices.
We use the ratio of net debt to cash flow from operating activities as a key
indicator of our leverage and to monitor the strength of our balance sheet. Net
debt is a non-GAAP measure that does not have any standard meaning prescribed by
GAAP and therefore may not be comparable to similar measures presented by
others. We calculate net debt using the GAAP measures of long-term debt and
short-term borrowings less cash and cash equivalents (excluding restricted
cash).
For the twelve months ended September 30, 2009, our net debt to cash flow from
operating activities ratio was 2.3 times compared to 1.1 times at December 31,
2008. While we typically expect the target ratio to fluctuate between 1.0 and
27
2.0 times under normalized commodity prices, this can be higher or lower
depending on commodity price volatility or when we identify strategic
opportunities requiring additional investment. Whenever we exceed our target
ratio, we assess whether we need to develop a strategy to reduce our leverage
and lower this ratio back to target levels over time.
Our interest coverage ratio monitors our ability to fund the interest
requirements associated with our debt. Our interest coverage was 7.2 times at
September 30, 2009 (December 31, 2008 - 15.6 times). Interest coverage is
calculated by dividing our twelve-month trailing adjusted EBITDA by interest
expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure. The
calculation of adjusted EBITDA is set out in the following table and is unlikely
to be comparable to similar measures presented by others.
Twelve Months Ended Year Ended
September 30 December 31
2009 2008
- ------------------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 96 1,715
Add:
Interest Expense 261 94
Provision for Income Taxes 174 1,457
Depreciation, Depletion, Amortization and Impairment 2,110 2,014
Exploration Expense 376 402
Recovery of Non-Cash Stock-Based Compensation (39) (272)
Change in Fair Value of Crude Oil Put Options 14 (203)
Other Non-Cash Expenses (210) (1)
----------------------------------------------
Adjusted EBITDA 2,782 5,206
==============================================
11. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our Property, Plant & Equipment (PP&E) are as follows:
Nine Months Ended Year Ended
September 30 December 31
2009 2008
- -------------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period 1,059 832
Obligations Incurred with Development Activities 25 32
Obligations Discharged with Disposed Properties (2) -
Obligations Settled (25) (45)
Accretion Expense 51 58
Revisions to Estimates (19) 159
Effects of Changes in Foreign Exchange Rate (62) 23
----------------------------------------------
Balance at End of Period (1)(2) 1,027 1,059
==============================================
(1) Obligations due within 12 months of $35 million (December 31, 2008 - $35
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $979 million
(December 31, 2008 - $1,009 million) and obligations relating to our
chemicals business amount to $48 million (December 31, 2008 - $50 million).
Our total estimated undiscounted inflated asset retirement obligations amount to
$2,353 million (December 31, 2008 - $2,393 million). We have discounted the
total estimated asset retirement obligations using a weighted-average,
credit-adjusted, risk-free rate of 5.9%. Approximately $367 million included in
our asset retirement obligations is expected to be settled over the next five
years. The remaining obligations settle beyond five years and are expected to be
funded by future cash flows from our operations.
12. DEFERRED CREDITS AND OTHER LIABILITIES
September 30 December 31
2009 2008
- -------------------------------------------------------------------------------------------------------------------------------
Deferred Tax Credit 542 709
Long-Term Energy Marketing Derivative Contracts (Note 6) 228 294
Defined Benefit Pension Obligations 71 67
Capital Lease Obligations 61 53
Deferred Transportation Revenue 57 69
Other 125 132
----------------------------------------------
Total 1,084 1,324
==============================================
28
13. SHAREHOLDERS' EQUITY
DIVIDENDS
Dividends per common share for the three months ended September 30, 2009 were
$0.05 per common share (2008 - $0.05). Dividends per common share for the nine
months ended September 30, 2009 were $0.15 per common share (2008 - $0.125).
Dividends paid to holders of common shares have been designated as "eligible
dividends" for Canadian tax purposes.
14. MARKETING AND OTHER INCOME
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Marketing Revenue, Net (Note 6) 188 149 676 381
Change in Fair Value of Crude Oil Put Options (Note 6) (23) 9 (218) (1)
Interest 1 7 4 20
Foreign Exchange Gains (Losses) 93 (33) 112 (34)
Other 37 (1) 61 21
---------------------------------------------------
Total 296 131 635 387
===================================================
15. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share using net income divided by the
weighted-average number of common shares outstanding. We calculate diluted
earnings per common share in the same manner as basic, except we use the
weighted-average number of diluted common shares outstanding in the denominator.
Three Months Nine Months
Ended September 30 Ended September 30
(millions of shares) 2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 521.7 525.9 521.0 528.3
Shares issuable pursuant to tandem options 10.3 19.6 10.7 24.9
Shares notionally purchased from proceeds of tandem options (7.0) (13.0) (7.5) (16.2)
---------------------------------------------------
Weighted-average number of diluted common shares outstanding 525.0 532.5 524.2 537.0
===================================================
In calculating the weighted-average number of diluted common shares outstanding
for the three and nine months ended September 30, 2009, we excluded 13,077,285
and 13,236,034 tandem options, respectively, because their exercise price was
greater than the average common share market price in the period. In calculating
the weighted-average number of diluted common shares outstanding for the three
and nine months ended September 30, 2008, we excluded 4,019,880 and 40,000
tandem options, respectively, because their exercise price was greater than the
average common share market price in the period. During the periods presented,
outstanding tandem options were the only potential dilutive instruments.
16. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 16 to the Audited Consolidated Financial Statements
included in our 2008 Form 10-K, there are a number of lawsuits and claims
pending, the ultimate results of which cannot be ascertained at this time. We
record costs as they are incurred or become determinable. We continue to believe
the resolution of these matters would not have a material adverse effect on our
liquidity, consolidated financial position or results of operations. There have
been no significant developments since year-end.
29
17. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 358 386 1,180 1,084
Stock-Based Compensation (19) (410) 23 (210)
Provision for (Recovery of) Future Income Taxes (81) 645 (397) 583
Change in Fair Value of Crude Oil Put Options 23 (9) 218 1
Allowance for Doubtful Accounts (4) 38 (5) 34
Foreign Exchange (117) 43 (154) 48
Other 14 (1) 22 4
---------------------------------------------------
Total 174 692 887 1,544
===================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Accounts Receivable 212 503 39 (821)
Inventories and Supplies (13) 260 (142) (128)
Other Current Assets (24) (64) (12) (80)
Accounts Payable and Accrued Liabilities (68) (1,607) 251 425
Other Current Liabilities 20 12 16 26
---------------------------------------------------
Total 127 (896) 152 (578)
===================================================
Relating to:
Operating Activities 113 (840) 193 (468)
Financing Activities - 10 - 10
Investing Activities 14 (66) (41) (120)
---------------------------------------------------
Total 127 (896) 152 (578)
===================================================
(c) OTHER CASH FLOW INFORMATION
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Interest Paid 70 64 248 212
Income Taxes Paid 179 655 247 816
---------------------------------------------------
Cash flow from other operating activities includes cash outflows related to
geological and geophysical expenditures of $16 million for the three months
ended September 30, 2009 (2008 - $38 million) and $59 million for the nine
months ended September 30, 2009 (2008 - $72 million).
30
18. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude, Energy
Marketing and Chemicals in various geographic locations as described in Note 22
to the Audited Consolidated Financial Statements included in our 2008 Form 10-K.
THREE MONTHS ENDED SEPTEMBER 30, 2009
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 176 92 74 478 16 137 9 115 - 1,097
Marketing and Other 3 (6) - 5 6 - 188 29 71 (2) 296
---------------------------------------------------------------------------------------------------------
Total Revenues 179 86 74 483 22 137 197 144 71 1,393
Less: Expenses
Operating 49 42 23 71 2 62 5 67 - 321
Depreciation, Depletion,
Amortization and
Impairment 19 59 67 162 2 13 14 12 10 358
Transportation and Other 7 8 2 3 - 5 141 13 6 185
General and
Administrative (3) 4 16 13 8 5 - 19 9 39 113
Exploration - 24 40 7 18 (4) - - - - 89
Interest - - - - - - - 2 82 84
---------------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 100 (63) (71) 232 (5) 57 18 41 (66) 243
Less: Provisions for
(Recovery 35 (15) (30) 102 (5) 14 8 9 (9) 109
of) Income Taxes
Less: Non-Controlling
Interests - - - - - - - 12 - 12
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 65 (48) (41) 130 - 43 10 20 (57) 122
=========================================================================================================
Identifiable Assets 241 7,756 (5) 1,880 5,157 976 1,244 3,114 (6) 704 1,997 23,069
=========================================================================================================
Capital Expenditures
Development and Other 11 135 31 133 130 17 9 53 7 526
Exploration - 42 46 32 9 - - - - 129
---------------------------------------------------------------------------------------------------------
11 177 77 165 139 17 9 53 7 655
=========================================================================================================
Property, Plant and
Equipment
Cost 2,516 9,558 3,957 6,165 782 1,424 250 1,086 356 26,094
Less: Accumulated DD&A 2,369 1,955 2,507 2,396 97 264 78 552 234 10,452
---------------------------------------------------------------------------------------------------------
Net Book Value 147 7,603 (5) 1,450 3,769 685 1,160 172 534 122 15,642
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $1 million, foreign exchange gains of $93
million and decrease in the fair value of crude oil put options of $23
million.
(3) Includes recovery of stock-based compensation expense of $5 million.
(4) Includes exploration activities primarily in Norway, Nigeria and Colombia.
(5) Includes costs of $5,946 million related to our insitu oil sands projects
(Long Lake and future phases).
(6) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
31
THREE MONTHS ENDED SEPTEMBER 30, 2008
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 317 192 139 1,141 56 220 17 131 - 2,213
Marketing and Other 2 1 - 6 1 3 149 (12) (19) (2) 131
---------------------------------------------------------------------------------------------------------
Total Revenues 319 193 139 1,147 57 223 166 119 (19) 2,344
Less: Expenses
Operating 39 48 29 66 2 68 10 79 - 341
Depreciation, Depletion,
Amortization and
Impairment 46 50 56 192 4 12 4 11 11 386
Transportation and Other 3 - 1 21 - 4 235 12 15 291
General and
Administrative (3) (20) (66) (28) (19) (45) - (4) 9 (135) (308)
Exploration 2 5 41 18 46 (4) - - - - 112
Interest - - - - - - - 3 13 16
---------------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 249 156 40 869 50 139 (79) 5 77 1,506
Less: Provisions for
(Recovery of) Income Taxes 86 44 13 444 (3) 40 (20) 2 13 619
Less: Non-Controlling
Interests - - - - - - - 1 - 1
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 163 112 27 425 53 99 (59) 2 64 886
=========================================================================================================
Identifiable Assets 365 6,301 (5) 1,951 6,502 536 1,218 4,468 (6) 541 333 22,215
=========================================================================================================
Capital Expenditures
Development and Other 29 245 46 189 35 19 2 24 10 599
Exploration - 34 38 43 11 - - - - 126
---------------------------------------------------------------------------------------------------------
29 279 84 232 46 19 2 24 10 725
=========================================================================================================
Property, Plant and
Equipment
Cost 2,402 7,697 3,670 5,558 358 1,363 268 896 322 22,534
Less: Accumulated DD&A 2,220 1,725 2,072 1,456 95 232 72 495 199 8,566
---------------------------------------------------------------------------------------------------------
Net Book Value 182 5,972 (5) 1,598 4,102 263 1,131 196 401 123 13,968
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $7 million, foreign exchange losses of $33
million, increase in the fair value of crude oil put options of $9 million
and other losses of $2 million.
(3) Includes recovery of stock-based compensation expense of $408 million.
(4) Includes exploration activities primarily in Norway and Colombia.
(5) Includes costs of $4,432 million related to our insitu oil sands projects
(Long Lake and future phases).
(6) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
32
NINE MONTHS ENDED SEPTEMBER 30, 2009
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 513 281 225 1,574 55 320 29 348 - 3,345
Marketing and Other 10 2 - 13 6 1 676 44 (117) (2) 635
---------------------------------------------------------------------------------------------------------
Total Revenues 523 283 225 1,587 61 321 705 392 (117) 3,980
Less: Expenses
Operating 145 125 73 175 6 205 21 196 - 946
Depreciation, Depletion,
Amortization and
Impairment 92 184 215 537 11 33 21 53 34 1,180
Transportation and Other 25 19 18 14 - 17 469 37 19 618
General and
Administrative (3) 5 58 51 15 29 1 68 34 119 380
Exploration - 53 87 26 53 (4) - - - - 219
Interest - - - - - - - 6 220 226
---------------------------------------------------------------------------------------------------------
Income (Loss) 256 (156) (219) 820 (38) 65 126 66 (509) 411
before Income Taxes
Less: Provisions for
(Recovery
of) Income Taxes 89 (39) (81) 358 (29) 16 52 15 (264) 117
Less: Non-Controlling
Interests - - - - - - - 17 - 17
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 167 (117) (138) 462 (9) 49 74 34 (245) 277
=========================================================================================================
Identifiable Assets 241 7,756 (5) 1,880 5,157 976 1,244 3,114 (6) 704 1,997 23,069
=========================================================================================================
Capital Expenditures
Development and Other 62 519 106 391 328 56 20 161 17 1,660
Exploration - 189 111 109 50 - - - - 459
Proved Property
Acquisitions - 755 - - - - - - - 755
---------------------------------------------------------------------------------------------------------
62 1,463 217 500 378 56 20 161 17 2,874
=========================================================================================================
Property, Plant and
Equipment
Cost 2,516 9,558 3,957 6,165 782 1,424 250 1,086 356 26,094
Less: Accumulated DD&A 2,369 1,955 2,507 2,396 97 264 78 552 234 10,452
---------------------------------------------------------------------------------------------------------
Net Book Value 147 7,603 (5) 1,450 3,769 685 1,160 172 534 122 15,642
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $4 million, foreign exchange gains of $112
million, decrease in the fair value of crude oil put options of $218
million and other losses of $15 million.
(3) Includes stock-based compensation expense of $51 million.
(4) Includes exploration activities primarily in Norway, Nigeria and Colombia.
(5) Includes costs of $5,946 million related to our insitu oil sands projects
(Long Lake and future phases).
(6) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
33
NINE MONTHS ENDED SEPTEMBER 30, 2008
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 912 545 518 3,053 156 567 52 351 - 6,154
Marketing and Other 9 2 4 17 2 3 381 (13) (18) (2) 387
---------------------------------------------------------------------------------------------------------
Total Revenues 921 547 522 3,070 158 570 433 338 (18) 6,541
Less: Expenses
Operating 129 137 77 186 7 208 33 221 - 998
Depreciation, Depletion,
Amortization and
Impairment 120 144 192 505 12 36 11 32 32 1,084
Transportation and Other 7 10 2 21 - 11 574 41 25 691
General and
Administrative (3) (4) (9) 13 23 (7) 14 1 63 24 43 165
Exploration 2 41 70 42 90 (5) - - - - 245
Interest - - - - - - - 8 51 59
---------------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 672 202 158 2,323 35 314 (248) 12 (169) 3,299
Less: Provisions for
(Recovery of) Income Taxes 234 57 55 1,181 (3) 89 (72) 5 (146) 1,400
Less: Non-Controlling
Interests - - - - - - - 3 - 3
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 438 145 103 1,142 38 225 (176) 4 (23) 1,896
=========================================================================================================
Identifiable Assets 365 6,301 (6) 1,951 6,502 536 1,218 4,468 (7) 541 333 22,215
=========================================================================================================
Capital Expenditures
Development and Other 61 855 180 410 73 39 3 57 23 1,701
Exploration 9 146 147 114 30 - - - - 446
Proved Property
Acquisitions - 2 - - - - - - - 2
---------------------------------------------------------------------------------------------------------
70 1,003 327 524 103 39 3 57 23 2,149
=========================================================================================================
Property, Plant and
Equipment
Cost 2,402 7,697 3,670 5,558 358 1,363 268 896 322 22,534
Less: Accumulated DD&A 2,220 1,725 2,072 1,456 95 232 72 495 199 8,566
---------------------------------------------------------------------------------------------------------
Net Book Value 182 5,972 (6) 1,598 4,102 263 1,131 196 401 123 13,968
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $20 million, foreign exchange losses of $34
million, decrease in the fair value of crude oil put options of $1 million
and other losses of $3 million.
(3) Includes severance accrual of $7 million in connection with North Vancouver
technology conversion project.
(4) Includes a recovery of stock-based compensation expense of $121 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes costs of $4,432 million related to our insitu oil sands projects
(Long Lake and future phases).
(7) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
34
19. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries
of differences from Canadian GAAP are as follows:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions, except per share amounts) 2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,097 2,213 3,345 6,154
Marketing and Other (v); (vi) 344 366 702 470
---------------------------------------------------
1,441 2,579 4,047 6,624
---------------------------------------------------
EXPENSES
Operating 321 341 946 998
Depreciation, Depletion, Amortization and Impairment 358 386 1,180 1,084
Transportation and Other (v) 191 291 616 687
General and Administrative (iv) 89 (272) 394 180
Exploration 89 112 219 245
Interest 84 16 226 59
---------------------------------------------------
1,132 874 3,581 3,253
---------------------------------------------------
INCOME BEFORE PROVISION FOR INCOME TAXES 309 1,705 466 3,371
---------------------------------------------------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 190 (26) 514 817
Deferred (iv); (vi); (vii) (68) 724 (384) 610
---------------------------------------------------
122 698 130 1,427
---------------------------------------------------
NET INCOME 187 1,007 336 1,944
Less: Net Income Attributable to Non-Controlling Interests (12) (1) (17) (3)
---------------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. - US GAAP (1) 175 1,006 319 1,941
===================================================
EARNINGS PER COMMON SHARE ($/share) (Note 15)
Basic 0.34 1.91 0.61 3.67
===================================================
Diluted 0.33 1.89 0.61 3.61
===================================================
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- ----------------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc - Canadian GAAP 122 886 277 1,896
Impact of US Principles, Net of Income Taxes:
Stock-based Compensation (iv) 17 (26) (11) (11)
Inventory Valuation (vi) 29 146 46 56
Deferred Taxes (vii) 7 - 7 -
---------------------------------------------------
Net Income Attributable to Nexen Inc - US GAAP 175 1,006 319 1,941
===================================================
35
UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
September 30 December 31
(Cdn$ millions, except share amounts) 2009 2008
- --------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 1,897 2,003
Restricted Cash 216 103
Accounts Receivable 2,877 3,163
Inventories and Supplies (vi) 601 426
Other 199 169
--------------------------------------
Total Current Assets 5,790 5,864
--------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $10,845 (December 31, 2008 - $10,786) (i); (iii) 15,593 14,873
GOODWILL 346 390
DEFERRED INCOME TAX ASSETS 916 351
DEFERRED CHARGES AND OTHER ASSETS 386 570
--------------------------------------
TOTAL ASSETS 23,031 22,048
======================================
LIABILITIES
CURRENT LIABILITIES
Accounts Payable and Accrued Liabilities (iv) 3,430 3,384
Accrued Interest Payable 81 67
Dividends Payable 26 26
--------------------------------------
Total Current Liabilities 3,537 3,477
--------------------------------------
LONG-TERM DEBT 7,429 6,578
DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii) 2,635 2,543
ASSET RETIREMENT OBLIGATIONS 992 1,024
DEFERRED CREDITS AND OTHER LIABILITIES (ii) 1,188 1,428
SHAREHOLDERS' EQUITY
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2009 - 521,846,559 shares
2008 - 519,448,590 shares 1,025 981
Contributed Surplus 1 2
Retained Earnings (i) - (vii) 6,413 6,172
Accumulated Other Comprehensive Loss (ii) (258) (209)
--------------------------------------
Total Nexen Inc. Shareholders' Equity 7,181 6,946
Canexus Non-Controlling Interests 69 52
--------------------------------------
TOTAL SHAREHOLDERS EQUITY 7,250 6,998
--------------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 23,031 22,048
======================================
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
- --------------------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. - US GAAP 175 1,006 319 1,941
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment (26) 41 (49) 60
---------------------------------------------------
Comprehensive Income Attributable to Nexen Inc. - US GAAP 149 1,047 270 2,001
===================================================
36
UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS - US GAAP
September 30 December 31
2009 2008
- -------------------------------------------------------------------------------------------------------------------------------
Foreign Currency Translation Adjustment (183) (134)
Unamortized Defined Benefit Pension Plan Costs (ii) (75) (75)
----------------------------------------
Accumulated Other Comprehensive Loss (258) (209)
========================================
NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS:
i. Under Canadian GAAP, we defer certain development costs to PP&E. Under US
principles, these costs have been included in operating expenses in prior
years. As a result PP&E is lower under US GAAP by $30 million (December
31, 2008 - $30 million).
ii. US GAAP requires the recognition of the over-funded and under-funded
status of a defined benefit plan on the balance sheet as an asset or
liability. At September 30, 2009 and December 31, 2008, the unfunded
amount of our defined benefit pension plans that was not included in the
pension liability under Canadian GAAP was $104 million. This amount has
been included in deferred credits and other liabilities and $75 million,
net of income taxes, has been included in Accumulated Other Comprehensive
Income (AOCI).
iii. On January 1, 2003, we adopted ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
for US GAAP reporting purposes. We adopted the equivalent Canadian
standard for asset retirement obligations on January 1, 2004. These
standards are consistent except for the adoption date which results in our
PP&E under US GAAP being lower by $19 million.
iv. Under Canadian principles, we record obligations for liability-based stock
compensation plans using the intrinsic-value method of accounting. Under
US principles, obligations for liability-based stock compensation plans
are recorded using the fair-value method of accounting. In addition, under
Canadian principles, we retroactively adopted EIC-162 which requires the
accelerated recognition of stock-based compensation expense for all
stock-based awards made to our retired and retirement-eligible employees.
However, US GAAP requires the accelerated recognition of stock-based
compensation expense for such employees for awards granted on or after
January 1, 2006. As a result under US GAAP:
o general and administrative (G&A) expense is lower by $24 million and
higher by $14 million ($17 million and $11 million, net of income
taxes) for the three and nine months ended September 30, 2009,
respectively (2008 - higher by $36 million and $15 million,
respectively ($26 million and $11 million, net of income taxes));
and
o accounts payable and accrued liabilities are higher by $72 million
as at September 30, 2009 (December 31, 2008 - $58 million).
v. Under US GAAP, asset disposition gains and losses are included with
transportation and other expense. Losses of $6 million and gains of $2
million for the three and nine months ended September 30, 2009,
respectively, were reclassified from marketing and other income to
transportation and other expense (gains of nil and $4 million were
reclassified for the three and nine months ended September 30, 2008).
vi. Under Canadian GAAP, we carry our commodity inventory held for trading
purposes at fair value, less any costs to sell. Under US GAAP, we are
required to carry this inventory at the lower of cost or net realizable
value. As a result:
o marketing and other income is higher by $42 million and $69 million
($29 million and $46 million, net of income taxes) for the three and
nine months ended September 30, 2009, respectively (2008 - higher by
$235 million and $87 million ($146 million and $56 million, net of
income taxes)); and
o inventories are higher by $11 million as at September 30, 2009
(December 31, 2008 - lower by $58 million).
vii. On January 1, 2007, we adopted ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES
regarding accounting and disclosure for uncertain tax positions. On the
adoption of this US guidance, we recorded a cumulative effect of a change
in accounting principle of $28 million. This amount increased our deferred
income tax liabilities, and decreased our retained earnings as at January
1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet. During the
quarter our uncertain tax position changed. As a result:
o Deferred income tax expense is lower by $7 million for the three and
nine months ended September 30, 2009 (2008 - nil); and
o Deferred income tax liabilities are higher by $21 million as at
September 30, 2009 (December 31, 2008 - higher by $28 million).
As at September 30, 2009, the total amount of our unrecognized tax benefit
was approximately $273 million, all of which, if recognized, would affect
our effective tax rate. To the extent interest and penalties may be
assessed by taxing authorities on any underpayment of income tax, such
amounts have been accrued and are classified as a component of income
taxes in the Unaudited Consolidated Statement of Income. As at September
30, 2009, the total amount of interest and penalties related to uncertain
tax positions recognized in deferred income tax liabilities in the US GAAP
37
- Unaudited Consolidated Balance Sheet was approximately $7 million. We
had no interest or penalties included in the US GAAP - Unaudited
Consolidated Statement of Income for the three and nine months ended
September 30, 2009.
Our income tax filings are subject to audit by taxation authorities and as
at September 30, 2009 the following tax years remained subject to
examination, (i) Canada - 1985 to date (ii) United Kingdom - 2007 to date
and (iii) United States - 2005 to date. We do not anticipate any material
changes to the unrecognized tax benefits previously disclosed within the
next 12 months.
CHANGES IN ACCOUNTING POLICIES - US GAAP
Business Combinations
On January 1, 2009, we prospectively adopted BUSINESS COMBINATIONS which
establishes principles and requirements of the acquisition method for business
combinations and related disclosures. The adoption of this statement did not
impact our results of operations or financial position.
NON-CONTROLLING INTERESTS
On January 1, 2009, we prospectively adopted NON-CONTROLLING INTERESTS IN
CONSOLIDATED FINANCIAL STATEMENTS. This statement clarifies that a
non-controlling interest in a subsidiary is an ownership interest in the
consolidated entity that should be reported as equity in the consolidated
financial statements. The adoption of this statement did not have a material
impact on our results of operations or financial position. The presentation
changes have been included in the Consolidated Financial Statements, as
applicable.
DERIVATIVE AND HEDGING ACCOUNTING AND DISCLOSURES
On January 1, 2009, we prospectively adopted DISCLOSURES ABOUT DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES. The statement requires qualitative
disclosures about the objectives and strategies for using derivatives,
quantitative data about the fair value of gains and losses on derivative
contracts and details of credit-risk-related contingent features in their hedged
position. The statement also requires the disclosure of the location and amounts
of derivative instruments in the financial statements. The disclosures required
by this standard are provided in Notes 6 and 7.
On April 1, 2009, we prospectively adopted three changes to FASB guidance
intended to improve guidance and disclosures on fair value measurement and
impairments. The positions clarify fair value accounting specifically regarding:
inactive markets and distressed transactions, other-than-temporary impairments,
and expanded fair value disclosures for financial instruments in interim
periods. The adoption of these positions did not have a material impact on our
results of operation or financial position.
SUBSEQUENT EVENTS
On April 1, 2009, we prospectively adopted SUBSEQUENT EVENTS. The new standard
reflects the existing principles of current subsequent events accounting
guidance and retains the notion and definition of "available to be issued"
financial statements. The new standard requires disclosure of the date through
which subsequent events have been evaluated and clarifies that original issuance
of financial statements means both "issued" or "available to be issued". The
adoption of this standard did not have a material impact on our results of
operation or financial position.
NEW ACCOUNTING PRONOUNCEMENTS - US GAAP
In December 2008, FASB issued EMPLOYERS DISCLOSURES ABOUT POSTRETIREMENT BENEFIT
PLAN ASSETS. This position provides guidance on disclosures about plan assets of
a defined benefit pension or other postretirement plans. This position is
effective for fiscal years ending after December 15, 2009. We do not expect the
adoption of this statement to materially impact our results of operations or
financial position.
In June 2009, FASB issued AMENDMENTS TO CONSOLIDATION OF VARIABLE INTEREST
ENTITIES. It retains the scope of the previous guidance with the addition of
entities previously considered qualifying special-purpose entities and
eliminates the previous quantitative approach for a qualitative analysis in
determining whether the enterprise's variable interest or interests give it a
controlling financial interest in a variable interest entity. The Statement is
further amended to require ongoing reassessments of whether an enterprise is the
primary beneficiary of a variable interest entity and requires enhanced
disclosures about an enterprise's involvement in a variable interest entity. The
Statement is effective at the beginning of the first annual reporting period
after November 15, 2009. We do not expect the adoption of this statement to have
a material impact on our results of operations or financial position.
38