the cenovus
equation
20 10 ann ual report
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Brian Ferguson talks about Cenovus, our
operations and how we’re doing things
differently. Want to see the video? Download
a free Qr code reader on your mobile browser.
Front cover: Staff from our Christina Lake site
Cenovus energy inC .
421 – 7 avenue sW
po Box 766
Calgary, alberta, Canada
t2p 0M5
printed in Canada.
We aRe a canaDian oiL coMP anY aPPLYinG
FResh, PRoGRessive thinKinG:
to safely and responsibly unlock energy resources
the world needs – that’s our promise.
to increase total shareholder return – that’s our goal.
pictured here is Foster Creek, our largest steam-assisted gravity drainage (sagD) project,
situated on the Cold lake air Weapons range in northern alberta.
Corporate Information
e xeCutive oFFiCers
Brian C. Ferguson
president & Chief executive officer
John K. Brannan
executive vice-president &
Chief operating officer
harbir s. Chhina
executive vice-president, oil sands
Kerry D. Dyte
executive vice-president, general
Counsel & Corporate secretary
Judy a. Fairburn
executive vice-president,
environment & strategic planning
sheila M. Mcintosh
executive vice-president,
Communications & stakeholder
relations
ivor M. ruste
executive vice-president &
Chief Financial officer
Donald t. swystun
executive vice-president, refining,
Marketing, transportation &
Development
hayward J. Walls
executive vice-president,
organization & Workplace
Development
BoarD oF DireCtors
Michael a. grandin(1)(4)(8)
Chair, Calgary, alberta
ralph s. Cunningham(1)(3)(4)(6)
houston, texas
patrick D. Daniel(1)(2)(3)(4)
Calgary, alberta
ian W. Delaney(1)(3)(4)(6)
toronto, ontario
Brian C. Ferguson(7)
Calgary, alberta
valerie a. a. nielsen(1)(2)(4)(5)
Calgary, alberta
Charles M. rampacek(4)(5)(6)
Dallas, texas
Colin taylor (2)(3)(4)
toronto, ontario
Wayne g. thomson(1)(4)(5)(6)
Calgary, alberta
(1) Former director of encana.
(2) Member of the audit committee.
(3) Member of the human Resources and
compensation committee.
(4) Member of the nominating and corporate
Governance committee.
(5) Member of the Reserves committee.
(6) Member of the safety, environment and
Responsibility committee.
(7) as an officer and a non-independent
director, Mr. Ferguson is not a member of
any of the committees of our Board.
(8) ex-officio non-voting member of all other
committees of our Board.
Cenovus he aD &
registereD oFFiCe
cenovus energy inc.
421 – 7 avenue s.W.
Po Box 766
calgary, alberta, canada t2P 0M5
Phone: 403-766-2000
www.cenovus.com
Shareholder Information
annual Meeting
shareholders are invited to
attend the annual meeting being
held on Wednesday, april 27, 2011
at 2 p.m. (calgary time) at the
teLus convention centre,
exhibition hall e, 2nd Floor,
north Building, 136 – 8 avenue s.e.,
calgary, alberta.
Please see our management
proxy circular mailed to
shareholders and posted on our
website, www.cenovus.com, for
additional information.
transFer a gents & registrar
in canada, ciBc Mellon trust
company in calgary, Montreal &
toronto. in the united states, BnY
Mellon in Jersey city, new Jersey.
shareholders are encouraged to
contact ciBc Mellon trust company
for information regarding their
security holdings. they can be
reached throughout north america
by phoning 1-866-332-8898 (english &
French) and outside north america
by phone at 1-416-643-5850 or by
facsimile at 1-416-643-5501.
Canadian stock transfer Company
CiBC Mellon trust Company
Po Box 7010
adelaide street Postal station
toronto, ontario, canada M5c 2W9
www.cibcmellon.com
canadian stock transfer company
inc. recently purchased the transfer
agency business from ciBc Mellon.
canadian stock transfer company
inc. is operating the transfer
agency business in the name of
ciBc Mellon trust company for a
transition period.
shareholDer
aCCount Matters
to change your address, transfer
shares, eliminate duplicate mailings,
deposit dividends directly into
accounts at financial institutions
in canada that provide electronic
fund-transfer services, etc.,
please contact ciBc Mellon
trust company.
stoCK e xChanges
common shares (cve) trade on
the toronto stock exchange
(tsX) and the new York stock
exchange (nYse).
annual inForMation ForM /
ForM 40-F
our annual information Form is
filed with the canadian securities
administrators in canada on
seDaR at www.sedar.com and with
the u.s. securities and exchange
commission under the Multi-
Jurisdictional Disclosure system
as Form 40-F on eDGaR at
www.sec.gov.
nyse s tat eMent oF
DiFFerenCes
as a canadian company listed
on the new York stock exchange
(nYse), we are not required to
comply with most of the nYse
corporate governance standards
and instead may comply with
canadian corporate governance
requirements. We are, however,
required to disclose the significant
differences between our corporate
governance practices and those
required to be followed by u.s.
domestic companies under the
nYse corporate governance
standards. except as summarized on
our website, www.cenovus.com, we
are in compliance with the nYse
corporate governance standards in
all significant respects.
investor rel ations
Please visit the Invest In Us
section of www.cenovus.com
for investor information.
investor inquiries should be
directed to:
403-766-7711
investor.relations@cenovus.com
or
susan grey
Director, investor Relations
403-766-4751
susan.grey@cenovus.com
Media inquiries should be
directed to:
403-766-7751
media.relations@cenovus.com
or
rhona DelFrari
Manager, Media Relations
403-766-4740
rhona.delfrari@cenovus.com
133 · c oRPoRate anD sh aRehoLDeR inFoRMat i on · ce n ov us 20 10 a nn u aL RePoR
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see how we add up
OUR ABILITY TO ACHIEVE OUR PROMISE AND
OUR GOAL REQUIRES A GREAT ASSET BASE AND
THE RIGHT PEOPLE DOING THE RIGHT THINGS.
WE HAVE BOTH. THE CENOVUS EQUATION SHOWS
HOW WE ADD UP.
This page We grow our oil sands projects in phases. Construction is currently underway for phases C and D at Christina Lake.
phase C, a 40,000 barrel-per-day expansion is expected to be completed in 2011. FaCing page The majority of Cenovus’s natural
gas production comes from our shallow gas operations in southern alberta. pictured here is a drilling rig near Brooks.
to results
OUR GREAT ASSETS PROVIDE THE fOUNDATION
fOR YEARS Of ENERGY DEVELOPMENT .
We have an industry-leading portfolio of oil sands assets, two high-quality refining assets,
a strong balance sheet, and low-cost conventional oil and natural gas operations that generate
substantial operating cash flow.
This page (CLoCkWise) a pumpjack at our Weyburn facility in saskatchewan / a natural gas wellhead near Brooks, alberta / The Wood
River Refinery in Roxanna, illinois jointly owned with Conocophillips. FaCing page We’re always looking for ways to improve how we
get our resources out of the ground. pictured here is equipment used for the solvent aided process (sap) at Christina Lake. sap is a
technology we’re piloting. it helps maximize the amount of oil recovered using sagD while reducing the environmental impact.
QUALITY RESOURCES + fINANCIAL STRENGTH = great assets
WE TAKE OUR COMMITMENT TO SMART
RESOURCE DEVELOPMENT SERIOUSLY. WE AIM
TO MAXIMIZE VALUE fOR OUR SHAREHOLDERS
WHILE SEEKING TO BALANCE ECONOMIC,
SOCIAL AND ENVIRONMENTAL PERfORMANCE.
This commitment guides the way we conduct our operations and is the foundation
of our 10-year business plan.
This page (CLoCkWise) speaking with a landowner / a Cenovus employee taking water samples / oil storage pipe racks coated
with fire proofing leaving our module fabrication yard in nisku for our Christina Lake facility. FaCing page our environmental
specialists inspect and analyze the land we’ll be using for our drilling activities before any operations begin. They then develop
a plan that will reclaim the land once a well is depleted. pictured here is new growth in the forest near our Foster Creek project.
STRONG EXECUTION + RESPONSIBLE OPERATIONS = smart resource development
WE HAVE A CULTURE THAT fOSTERS NEW IDEAS AND
NEW APPROACHES IN ALL ASPECTS Of OUR BUSINESS.
In our operations, technology plays a key role in extracting the resources – enhancing the
amount recovered and improving the methods we use to get the oil and natural gas out of the
ground. An ongoing objective is to advance innovative technologies that reduce the amount of
land, water and energy we use.
This page (CLoCkWise) Foster Creek control room / Building a culture of knowledge sharing through staff information sessions /
solar panels in some of our operations provide power to remote instruments, allowing for data communication back to our main
facility / staff at our Weyburn facility. FaCing page The plants at our oil sands facilities are largely water plants that require a
complex system of pipes to transport steam and fluids used in the sagD process. pictured here is our Christina Lake facility.
INNOVATION + CONTINUOUS IMPROVEMENT = leading technology
WE HAVE YEARS Of EXPERIENCE IMPROVING WHAT
WE DO. A TRACK RECORD Of DELIVERING GREAT
PERfORMANCE. A PASSION fOR RESULTS.
The people at Cenovus are dedicated and enthusiastic about improving every aspect of
our business. Experienced in turning ideas into action, and committed to doing right by the
environment and our communities. We are proud to have the right people doing the right
things to provide the energy resources the world needs and relies on every day.
This page (CLoCkWise) adjusting a bolt on a pumpjack in Langevin / Cenovus staff in a meeting / operators at Christina Lake.
FaCing page at Cenovus it’s important our equipment is operating at an optimal level. our employees are always looking for ways
to improve equipment reliability and performance. pictured here is a mechanic at our Weyburn facility completing preventative
maintenance on mechanical components.
KNOWLEDGE + DEDICATION = the right people
our people bring energy, focus and dedication to their work.
pictured here is an operator at Christina Lake.
CENOVUS 201 0 A NNUA L REPO RT · S E CTI ON TI TL E · 12
As a company we are: Rigorous. Respectful. Ready.
We have the resource, the strategy and a track record
of strong results. As a team, we have the passion for
operational excellence, the commitment to finding
better ways of doing things and respect for the
environment and the communities where we live
and work. That’s how we add up to results.
13 · SECTION TITLE · CENOVUS 2 01 0 ANNUAL REPO RT
great assets sMart resOUrCe DeVeLOPMeNt LeaDiNg teChNOLOgythe right PeOPLecenovus Operating adjustments may be required to ensure our treated oil meets pipeline sales specifications
before it’s shipped to market. Pictured here is an operator conducting oil sampling at foster Creek.
TaBLe oF C onTenT s
Strategy snapshot ........................................................................................................................................................................................................................................................................................ 16
Meet our Executive Team ........................................................................................................................................................................................................................................................................ 19
Message from our President & Chief Executive Officer ............................................................................................................................................................................................................ 21
Q&A with our Chief Operating Officer ..............................................................................................................................................................................................................................................23
2010 year in review ...................................................................................................................................................................................................................................................................................... 25
Meet our employees .................................................................................................................................................................................................................................................................................. 29
Meet our Board of Directors ................................................................................................................................................................................................................................................................... 31
Message from our Board Chair ...............................................................................................................................................................................................................................................................32
Operating and financial highlights ........................................................................................................................................................................................................................................................33
Management’s discussion and analysis .............................................................................................................................................................................................................................................. 34
Consolidated financial statements ...................................................................................................................................................................................................................................................... 78
Notes to consolidated financial statements .................................................................................................................................................................................................................................. 85
Supplemental information .................................................................................................................................................................................................................................................................... 120
Reserves data and other oil and gas information ........................................................................................................................................................................................................................126
Corporate and shareholder information ......................................................................................................................................................................................................................................... 133
Fccl/wrB partnership our business venture with Conocophillips provides
integration of oil sands and refining operations. This venture provides Cenovus
with a 50 percent interest in the Wood River (illinois) and Borger (Texas)
refineries; in return Conocophillips has a 50 percent interest in certain
Cenovus oil sands properties, notably Foster Creek, Christina Lake and
narrows Lake. For additional information, see our MD&a.
Forward-looking information Our Annual Report contains forward-looking information about our
strategy, milestones, goals, targets and future expectations. This forward-looking information is based
non-gaap measures Our Annual Report contains references to certain financial measures which
do not have a standardized meaning as prescribed by GAAP. A description of each non-GAAP
on certain factors and assumptions and is subject to risks and uncertainties, some of which are specific
measure, including a definition and reconciliation with GAAP measures, is included in our MD&A.
to Cenovus and others that apply to the industry generally. for details about these factors, assumptions,
risks and uncertainties, please refer to the Advisory section in our MD&A. All estimated timelines are
subject to regulatory and/or partner approval. Readers are cautioned not to place undue reliance on
forward-looking information as our actual results may differ materially from those expressed or implied.
for an overview of our risk management, see the Risk Management section of our MD&A.
oil and gas information Our Annual Report contains information about our reserves and our
bitumen resources. for additional information about our reserves, contingent and prospective
resources, see the Oil and Gas Reserves and Resources section of our MD&A and the Advisory
section of our MD&A. for additional information about our total and discovered bitumen
initially-in-place, see the Additional Advisory on page 132.
15 · TABLE Of CONTENTS · CENOVUS 201 0 ANNUAL REP ORT
sTRa TegY snapsho T
Increasing total return to our shareholders is the
cornerstone of our 10-year business plan. With our
high-quality oil opportunities, our track record of strong
execution and our financial strength, we plan to achieve
increased shareholder return in two ways:
naV is a comprehensive
measure well suited to
the long-term nature of
oil sands development.
doublE
NAV *
by 2015
&
pAy A
stroNg ANd
sustAiNAblE
diVidENd
iNcrEAsE
oil sANds
productioN
from
60thousANd
bbls/d† iN 2010
to
300thousANd
bbls/d† iN 2019
We plan to maintain financial
flexibility and optimize cash flow to
grow our business and provide an
income stream to shareholders.
mAiNtAiN stroNg
pErformANcE
from
coNVENtioNAl
oil ANd NAturAl
gAs AssEts
* NAV: Net asset value (total value of assets minus total value of liabilities)
† Net to Cenovus
CENOVUS 201 0 A NNUA L REPO RT · S TRATE GY S NA PSHOT · 16
sTRa Teg Y snapsho T
We plan to double net asset value and pay a strong
and sustainable dividend by leveraging these three
strategic advantages:
oil opportunities
track record of performance
financial strength
bArrEls of
discoVErEd biip*
56
billioN
AmouNt dEfiNEd
through drilliNg
14 yEArs
oil sANds
opErAtiNg
history
iNtErNAlly
fuNdEd growth
through stroNg
cAsh flow ANd
bAlANcE shEEt
Vast majority of our total
proved + probable reserves are
bitumen, conventional oil and
ngLs** – 88% of 2.4 billion
barrels of oil equivalent.
growth
driVEr:
oil
Track record of being a low-cost
operator who delivers strong
financial results. We have best-in-
class capital efficiencies, low soRs***
and a manufacturing approach to
our business.
increasing contribution to upstream
operating cash flow from oil and ngLs.
2010: 63% 2019F: 80%
goal: increase oil sands production
five-fold by the end of 2019 by:
• converting resources into reserves
• continuing development of our
high-quality, low-cost, oil sands projects
• advancing regulatory approvals
• advancing emerging oil sands projects
projEct
ApproVAls
400 to 500
thousANd bbls/d†
by 2015
tEchNology
iNNoVAtioN
soR is the amount of steam needed
to produce a barrel of oil, a key
measure of efficiency for operations
using sagD technology. a low soR
means you’re more energy efficient,
have lower costs and have a smaller
environmental impact.
We continue to be committed
to improving our recovery
rates and reducing our impact on
the environment.
our investment grade credit ratings
reflect our quality assets, solid
capital structure, financial flexibility
and significant liquidity.
our established base of conventional
oil and natural gas assets generates
operating cash flow to fund our oil
sands growth.
our hedging program manages
commodity price exposure and locks
in cash flow.
*BIIP: bitumen initially-in-place; see Additional Advisory on page 132
**NGLs: natural gas liquids
***SOR: steam to oil ratio
† Net to Cenovus
17 · STRATEGY SNAPSHOT · CENOVU S 20 10 ANNUA L REPORT
sTRa TegY snapsho T – MiLes Tones
Delivering on our business plan: We have set specific
milestones to measure our achievements as we grow our
business and build NAV.
2010
2011f
2012f
achieved milesto ne s
mile stones se t so F ar
mile stones se t so F ar
shaped our teams, systems and culture;
developed our policies and practices; and set
the strategic direction for our company
announced plan to increase oil sands production
to 300,000 bbls/d net by end of 2019
assessed oil sands resources, disclosed bitumen
initially-in-place and provided more details
about how we will grow our oil sands projects
grew reserves and contingent resources
submitted regulatory application for narrows
Lake (one of our emerging oil sands projects)
Received regulatory approval and initiated
sanctioning process for Foster Creek phases
F, g & h
Received regulatory approval for grand Rapids
sagD pilot project and began first steam
Restructured our internal organization to
better align with our business plan
Delivered excellent operating and
financial results
Divested non-core assets
established long-term agreement with
Conklin community
grow reserves and contingent resources
grow reserves and contingent resources
execute stratigraphic well program (drill 450
wells) and assess results
initiate sanctioning process for narrows Lake
phases a, B & C
advance environment key performance
indicators and long-term impact forecasting
Drill 400 to 500 stratigraphic wells and
assess results
sanction Foster Creek phases F, g & h
implement at least one new commercial
technology from Cenovus’s R&D program
achieve first production at Christina Lake
phase C
start gas cap air injection for thermal
oil recovery pilot at Clearwater
anticipate receipt of regulatory approval for
Christina Lake phases e, F & g and commence
sanctioning process for e
increase production from pelican
Lake Wabiskaw
expand the polymer flood and drill additional
infill wells at pelican Lake, which is expected to
result in higher production
submit grand Rapids regulatory application for
a commercial operation
start up coker as part of Wood River
CoRe project
implement the Cenovus operations
Management system (CoMs)
implement at least one new commercial
technology from Cenovus’s R&D program
integrate the six commitment areas of our
Corporate Responsibility policy into the
company’s business strategy in order to
create value for both our business and the
communities where we live and work
CENOVUS 201 0 A NNUA L REPO RT · S TRATE GY S NA PSHOT – M IL ESTON ES · 18
MeeT ouR e xeCuTiVe Te aM
The Cenovus Executive Team members bring expertise and
energy to their roles. Collectively, they inspire our teams and
steer the success of our business.
BROAD KNOWLEDGE + COLLABORATIVE APPROACH = strong leadership
(Pictured left to right)
iVoR M. Rus Te
executive Vice-president &
Chief Financial officer
JuDY a . FaiRBuRn
executive Vice-president,
environment & strategic planning
keRRY D . DYTe
executive Vice-president,
general Counsel & Corporate secretary
haR BiR s . Chhin a
ha YWaRD J. WaLLs
executive Vice-president, oil sands
J ohn k . BRannan
executive Vice-president &
Chief operating officer
BRian C . FeR guso n
executive Vice-president, organization &
Workplace Development
sheiL a M. MC inT os h
executive Vice-president,
Communications & stakeholder Relations
president & Chief executive officer
Do n T . sWY sTun
executive Vice-president, Refining, Marketing,
Transportation & Development
19 · MEET OU R E XECUTIVE TE AM · CENOVU S 20 10 ANNUAL REPORT
MeeT ouR e xeCuTiVe Te aM
Everything
we do is about
increasing the
value of the
company. Our
goal is to double
our net asset
value by 2015.
BRian FeR guson
Engaging
with our various
stakeholders and
telling the
Cenovus story
is critical to our
success. We have
a great story
to tell.
We’re building a vibrant and healthy organization
that differentiates Cenovus.
We have the
financial strength
and flexibility
to enable our
ambitious plans.
iVoR Rus Te
Our
commitment to
safety, new ideas
and improved
technologies
is strong. The
status quo is
unacceptable at
Cenovus.
Innovation
unlocked the
oil sands. That
kind of ingenuity
will tackle the
environmental
challenges.
JuDY FaiRBuRn
haYWaRD W aLLs
We strive
to be industry
leading in our
operations –
from our
approach
to our results.
John BRannan
Our approach
to governance
provides a strong
framework for
achieving our
plans.
Our
downstream
integration gives
us less volatility
and balances
our commodity
exposure.
sheiL a MCinT osh
haRBiR Chhina
keRRY D YTe
Don sWY sTun
CENOVUS 201 0 A NNUA L REPO RT · M EE T OUR E XE CUT IVE TE A M · 20
Message FR oM ouR pResiDenT & ChieF e xeCuTiVe oF FiCeR
“ You can count on Cenovus’s commitment
to develop our resources safely and responsibly,
and to always strive to be better at how we do it.”
CLEAR VISION + SMART EXECUTION = an exciting Future
By the end of 2010, our efforts throughout the
year resulted in an independent evaluation
determining that our proved bitumen reserves
had increased by 33 percent over 2009 to nearly
1.2 billion barrels.
A particular highlight was that our foster Creek
and Christina Lake facilities increased production
by 33 percent in 2010 compared with 2009, for
a combined production of over 59,000 barrels
per day net to Cenovus. At the same time, our
operating costs at these facilities decreased 10
percent in 2010 compared to 2009, to an average
and focusing on increasing production from our
high-quality oil sands assets.
As part of our 10-year plan, we have set clear
milestones to measure our success, which are
outlined on page 18. The nature of oil sands
means we are in a long-term business – so it’s
important that you know our milestones and can
track our progress.
I am pleased to report that we met or exceeded
all the key milestones we set for 2010.
In everything we do, our aim is to increase value
for you, our shareholders. We are targeting to
double our net asset value by 2015, and boost our
oil sands production five-fold to 300,000 barrels
per day net to Cenovus by the end of 2019. We
also expect to provide you with a strong and
sustainable dividend.
2 010 – seTTing The s Tag e FoR FuTuRe
VaLue CRe a Tio n
Early in 2010, we undertook a third-party
assessment to fully understand our oil sands
resource. The evaluation, using some of the most
rigorous standards in the industry, identified
best estimate total bitumen initially-in-place on
Cenovus lands of 137 billion barrels, of which
56 billion barrels are considered discovered.
We created our long-term plan to take
advantage of these tremendous assets by
focusing on bringing this high-quality resource
into production.
BRI A N C . fERGUSO N
PRESI DENT & CHI Ef E XECUTIVE OffICER
With our first full year as an independent oil
company behind us, I am proud of what we
have accomplished at Cenovus in such a short
time. It gives me great pleasure to report our
accomplishments to you in this, our first annual
report to shareholders.
2010 was a year of strong operational results,
exceptional reserves growth and solid financial
performance. One where we shaped our teams,
our systems and our culture. Most importantly,
it was one where we positioned Cenovus for
future success by setting the strategic direction
for our company. We did this by assessing our
vast resource to better understand our growth
opportunities, developing a 10-year business plan,
21 · MESSAGE fROM OUR PRESIDENT & CHIEf E XECUTIVE OffICER · CENOVUS 2010 A NNU AL REPORT
Our proposed SAGD development in the oil sands is driving our growthOil sands production Mbbls/d (net to Cenovus)20102019F30050100150200250 of $11.28 per barrel – all while we were operating
with even more emphasis on working safely. To
the credit of our entire operations team, their
focus on safety resulted in fewer total incidents
during the year.
We furthered our expansions at both foster
Creek and Christina Lake in 2010 and advanced
development plans at two of our emerging
projects, Narrows Lake and Grand Rapids. As well,
our established oil and natural gas properties
in Alberta and Saskatchewan continued to
demonstrate strong cash-generating abilities,
providing approximately $1.3 billion of operating
cash flow in excess of their capital expenditures
in 2010. The cash generated from our conventional
oil and natural gas properties funds our
continued oil sands growth, and the natural
gas also fuels our oil sands and
refining operations.
In our refining operations, we continued to
concentrate on increasing capacity through a
coker and refinery expansion (CORE) project
at our Wood River Refinery in Illinois. Upon
anticipated start up of the coker in the fourth
quarter of 2011, we expect improved profitability
from this part of our business.
Managing our business with a continued focus
on value creation and cost control resulted
in Cenovus having an even stronger financial
position at the end of 2010 than at the start of
the year. We have a healthy balance sheet, closing
2010 with a debt to capitalization ratio of
26 percent and debt to adjusted EBITDA ratio of
1.2 times. Total cash flow was strong at $3.21 per
share for the year, while our capital investment
in 2010 was $2.1 billion. At Cenovus, we take a
responsible and careful approach to our financial
strategy. We are committed to continuing to
provide our shareholders with regular dividend
payments as part of this disciplined approach.
You can read more about our accomplishments in
the 2010 Year in review section on pages 25 to 28
of this report.
Another significant action we undertook in 2010
was to organize ourselves internally to maximize
efficiencies and better align our structure with
our plan. We accomplished this by eliminating
our operating divisions and creating a centralized
operations team under the leadership of John
Brannan, who assumed the new position of
Executive Vice-President & Chief Operating
Officer. John brings more than 30 years of oil and
natural gas experience to this new role, and his
leadership will drive continued achievements in
our operations.
“2010 was a year of strong operational
results, exceptional reserves growth
and solid financial performance.
One where we shaped our teams,
our systems and our culture. Most
importantly... we positioned Cenovus
for future success by setting the
strategic direction for our company.”
2 011 – B uiLDing on o uR 20 10 MoMe nTuM
With the foundation of our company in
place, 2011 will be focused on building on the
momentum we achieved in 2010, by pursuing
regulatory approvals, advancing construction
of the expansion phases at foster Creek and
Christina Lake, and pursuing opportunities for
production growth in the Greater Pelican Region.
The milestones we have set for 2011 align with our
10-year business plan and our goal of growing net
asset value. They include executing our largest-
ever stratigraphic well program to evaluate our
undeveloped land, expand our contingent resource
and advance projects into the regulatory queue.
As well, we are focused on delivering on our
upstream operational targets and keeping our
projects on schedule and on budget, so we can
continue to crystallize the value our great assets
provide for our company and our shareholders.
Cenovus shares outperformed the market in 2010
Total shareholder return (TSX)
Percentage
30
15
0
CE N OVUS ENERGY
S&P/TSX COMPOSITE INDEX
S & P/TSX ENERGY INDEX
THE VALUE Of A CENOVUS HOLDING WAS UP 29 PERCENT
ON THE BA SI S Of ALL DIVIDEND PAYMENTS BEING
RE IN VE STE D COMPARED WITH AN 18 PERCENT
IN CRE AS E IN THE S &P/ TSX C OMPOSITE INDE X AND
13 PE RC EN T fOR THE S &P/ TSX ENERGY INDE X .
The Cen oVus eq ua Tio n –
o uR keY s TRen gThs
What sets Cenovus apart is the combination
of our great financial and operating assets, our
commitment to responsible operations, our
ability to advance technology to improve our
results, and the 3,500 dedicated people who
make it all happen. People who bring decades
of experience, knowledge and enthusiasm to
their work. Thanks to them, we are able to
develop new ideas, new technologies and
better approaches.
I am proud of our achievements in bringing
Cenovus to this point, and would like to
acknowledge and thank our Board of Directors,
our Executive Team, and our employees and
contractors for demonstrating such dedication to
Cenovus’s success. We have an air of excitement,
a can-do attitude and a driving passion to make
Cenovus the best it can be. In a year of change,
we maintained focus on building our company,
we delivered on our targets, and we had excellent
operating and financial results.
We are building a company that, at its core,
believes in doing right by the environment and
the communities where we live and work. We are
focused on doing the right things to help provide
the energy resources the world needs and relies
on every day.
With demand for energy growing, you can count
on Cenovus’s commitment to develop our resources
safely and responsibly, and to always strive to
be better at how we do it. It’s at the heart of the
Cenovus equation. And it’s our promise to you.
We have set ambitious goals for ourselves, but
I believe we are in a strong position to realize
our tremendous future. Our Executive Team and
I look forward to the exciting possibilities that
lie ahead.
CENOVUS 201 0 A NNUA L REPO RT · M ESS AGE fRO M OUR P RE S I DE NT & C HIEf E XECU TIVE OffICER · 22
q& a WiTh ouR ChieF opeRa
Ting oFFiCeR
“As a unified operations team we will be better positioned
to continue our focus on maintaining our operating
momentum, delivering on our business plan and being a
safe, responsible operator.”
GREAT TRACK RECORD + fRESH THINKING = operational excellence
the way we work and take advantage of knowledge
sharing and technology improvements across our
business. Additionally, the unified operating team is
supported by a central organization for regulatory,
drilling, procurement, continuous improvement,
land functions, process improvement, and
health and safety. Most importantly, as a unified
operations team we will be better positioned to
continue our focus on maintaining our operating
momentum, delivering on our business plan and
being a safe, responsible operator.
Cenovus believes it’s important
to be a low-cost operator. How
do you achieve that?
We’re recognized in the industry as being a low-
cost operator with leading capital efficiencies
and we’re proud of our track record. Our low
costs are the result of a number of factors. While
it’s true that our low steam to oil ratios and high-
quality reservoirs allow us to keep costs down,
it’s also due to the manufacturing approach we
take in the design, construction and operation
of our facilities. Our teams build our projects in
manageable phases using repeatable designs. We
design the process flow diagrams, equipment, and
operating processes to be similar at all our SAGD
facilities. Our teams then apply their experience
and learnings to each new phase and implement
advancements in technology once they’ve
become proven – all with the goal of improving
efficiency and reducing costs, without sacrificing
our commitment to high-quality facilities, safe
operations and minimal environmental impact.
How do you manage cost
inflation in your business?
We have a philosophy at Cenovus that holds
everyone accountable for spending our money
wisely regardless of the economic environment.
So having that kind of overall attentiveness gives
us an advantage when dealing with inflation.
One way we manage inflation is through our
approach to development. for example, by using
in-house construction management teams, we
take control of our costs and reduce potential
for overruns by having Cenovus staff accountable
for capital spending.
Another way we manage inflation is through
our module fabrication yard in Nisku, Alberta,
located just outside of Edmonton. Having an
established module yard allows us to control
costs and maintain schedules and greatly reduces
the amount of rework needed in the field. As an
example, out of the 145 modules required for
the Christina Lake phase C expansion, only two
modules required minor modifications during
installation – obviously a significant cost and
time savings and a substantial increase in the
efficiency of our construction teams.
23 · Q& A WITH OUR CHIEf OPERATING OffICER · CENOVUS 2010 ANNUA L REPO RT
JOHN K . BRA NN AN
E XE CU TIVE VI C E-PRESI DE N T
& C HI Ef OP ERATIN G Of fICE R
Late in 2010 you were named
Cenovus’s Chief Operating
Officer. How does this
new role change Cenovus’s
approach to operations?
Let me start by saying I’m really pleased to
be working closely with all the areas of our
operations – our oil sands, conventional oil and
natural gas teams, as well as our refining and
marketing teams. Everyone has been doing great
work. Having one operating team rather than
separate operating divisions allows us to optimize
The location of our projects also helps us control
inflation. We’re fortunate to be located near
Bonnyville, Cold Lake and Lac La Biche, which
experienced lower inflation than areas such as
fort McMurray during the last upswing in oil
sands activity.
Lastly, where we can, we train and hire locally and
use businesses and services in the areas around
our operations. It’s important to us that we work
with local communities and stakeholders to
establish a win-win scenario for all.
Cenovus talks a lot about
steam to oil ratio. What
is it and why is it such an
important measure?
Steam to oil ratio, or SOR, is the amount of
steam required to produce one barrel of oil.
It’s a reflection of the quality of the reservoir
and the approach used to develop the resource.
It’s also the single most important factor that
influences the economics of a SAGD project, the
lower the SOR, the better. Approximately
60 to 70 percent of a SAGD plant’s function
is dedicated to water handling for steam
production. We currently have some of the
lowest reported SORs in the industry. In 2010, our
demonstrated SORs at foster Creek and Christina
Lake were about 2.2 combined. A low SOR means
we need less steam to produce oil so, on a per
barrel basis, it means better capital efficiency
indicated by our lower capital costs.
Our most significant operating cost stems from
burning natural gas to turn water into steam.
Our low SOR keeps our operating costs at a
minimum. It also leads to other benefits such as
a smaller surface footprint, lower emissions and
reduced water use, which help us meet
our environmental objectives as well as our
financial objectives.
I’m extremely proud of the work we’ve done to
successfully lower our SOR.
Cenovus has made a
commitment to implement
at least one new commercial
technology per year.
Why is research and
development so critical to
the company’s success?
Research and development is a huge focus
for Cenovus. Historically, we’ve been able to
implement at least one new technology in our
operations each year and believe we can continue
that trend.
Take the development of SAGD for example. We
believe that this technology, which has only been
commercially applied for about a decade, still has
opportunities for improvement with respect to
developing and optimizing our recovery schemes.
We plan to continue to lead the industry in
implementing new approaches to how we’re able
to extract the oil out of the ground. Our recent
use of wedge wells is a great example of that. It’s
a Cenovus technology that’s already changing
the way we develop our assets, and we haven’t
even begun to fully utilize it in our operations. At
year end 2010, about 13 percent of foster Creek’s
total production came from wedge wells, which
cost only about half the amount required to drill a
SAGD well pair. At the end of 2010 we had drilled
51 wedge wells at foster Creek with 33 producing,
and had one producing wedge well at Christina
Lake. Building on this success, we’re planning to
drill 10 more wedge wells at foster Creek in 2011.
We believe research and development is
critical to the longevity of our business, which
is why our ability to advance technology is an
important part of who we are as a company.
It’s how we’ve increased efficiency, recovery
and project returns. It’s also reduced our costs
and our overall environmental intensity. And
it’s how we’re going to continue to improve our
operations in the future.
W EDGE WELL TECH NOLOGY
This simplified
diagram shows the
‘wedge’ of oil between
two well pairs that was
previously inaccessible.
P
E
E
D
m
0
5
4
X
O
R
P
P
A
WEDGE WELL
WEDGE WELL
RECOVE RY ARE A
INJECTOR WELL
PRODUCER WELL
WEDGE WE LL S ARE SINGLE HORIZONTAL WELLS
DRILLED BETWEEN TWO SAGD WELL PAIRS TO CAPTURE
P REVIOUS LY I NACCESSIBLE OIL IN TH E R ESERVOIR
THEY REQ UIRE LITTLE OR NO STE AM TO E XTR ACT
THE REM AIN ING OIL , MAKING IT POSSIB LE TO
INCREASE OIL RECOVERY WHILE REDUCING OPERATING
COSTS , WATE R USE AND ENERGY USE PER BARREL
.
.
If oil sands are your growth
driver, what role do your other
resources play?
We have a great balance of growth and financial
assets. We think of our conventional oil and
natural gas properties as financial assets. They are
low-cost, high-return assets that, with modest
capital investment, will generate substantial
operating cash flow and will experience a fairly
shallow decline. Our natural gas business also acts
as an economic hedge against price fluctuations,
because natural gas fuels our oil sands and refining
operations. Our oil operations include Weyburn
and other properties in southern Alberta and
Saskatchewan while our natural gas properties are
in Alberta. On the growth front, in addition to the
CENOVUS 201 0 A NNUA L REPO RT · Q & A WI TH OUR CH I Ef OP E RATIN G OffICER · 24
growth from our oil sands, we expect to double
heavy oil production at Pelican Lake as a result of
our multi-year infill drilling program.
When will the Coker and
Refinery Expansion (CORE)
project at Wood River
be complete?
The CORE project is a large-scale expansion that
started in September 2008 at our Wood River
Refinery in Illinois, which is designed to process
306,000 barrels per day of crude oil. Construction
is expected to be substantially complete in the
third quarter of 2011, with start up of the coker
expected in the fourth quarter. Once complete,
Wood River will join our Borger Refinery in Texas
as one of the more complex refineries in the
United States. The increased complexity is a result
of adding a new coker, associated processing
units and other upgrades to the existing refinery.
Together, they will provide the refinery with
the flexibility to take advantage of lower cost
feedstocks and improve overall refining capacity
and yields. The refinery modifications will increase
Wood River’s crude capacity by 50,000 barrels
per day and heavy crude oil capacity will more
than double to 240,000 barrels per day. These
downstream assets protect us against wide light/
heavy differentials and enable us to extract value
across the entire chain from bitumen all the way
to transportation fuels.
Safety is a core value at
Cenovus. How do you ensure
that value translates into
action and results in a good
safety record?
The health and safety of our workforce is of
paramount importance at Cenovus. But it’s not
just about saying it. It’s about living it every day.
We have eight safety commitments that guide
how we conduct our business. All eight are
critical to reinforcing the behaviour and attitude
we want to see in our staff, but the first one best
illustrates our commitment to safety. It states,
‘Our work is never so urgent or important that we
cannot take the time to do it safely.’
While these commitments are the foundation
of our goal to have an injury-free workplace,
they are put into practice through awareness,
education and empowerment of our employees
and contractors. Most gratifying of all is that
our increased focus on safety has resulted in a
significant reduction of on-the-job injuries over
the past three years. And that’s what’s really
important. Because working at Cenovus really
does mean working safely.
2010 Ye aR in ReVi eW
In our first full year as an independent company, we achieved
a number of milestones and delivered on our commitment
to develop energy resources safely and responsibly. We
met production targets while maintaining safe, disciplined
operations. We accelerated expansions at our core oil sands
operations, foster Creek and Christina Lake. Cenovus is well
positioned for future success.
KEY MILESTONES ACHIEVED + STRONG RESULTS = a year to Be proud oF
sTRong 2010 Res uLT s
enterprise value: $28.5 billion (1)
shares outstanding: 752.7 million (1)
oil & ngLs production: 129 Mbbls/d
natural gas production: 737 MMcf/d
proved & probable reserves: 2.4 billion BOE(1)
Total acreage: 7.2 million net acres(1)
Bitumen acreage: 1.4 million net acres (1)(2)
Refining capacity: 226 Mbbls/d
All numbers shown are net to Cenovus on a before
royalties basis.
(1) As at December 31, 2010.
(2) Includes exclusive rights to lease 0.6 million net acres on
our behalf and/or our assignee’s behalf.
DeVeL opeD ouR 10- Ye aR Bus ine ss pL an
Approved June 2010 by our Board of Directors.
See the Strategy snapshot on page 16.
ChangeD ouR oR g an izaTio naL
sTRuCTuRe
We replaced our operating divisions with a
centralized operations team. It took effect
December 1, 2010.
Co nFiRMeD ouR V asT
oiL s anD s poTenTi aL
An independent evaluation was completed in the
spring of 2010 that confirmed 5.4 billion barrels
of best estimate bitumen economic contingent
resources on Cenovus’s lands. A subsequent
independent evaluation was completed at the
end of 2010 that confirmed 6.1 billion barrels of
best estimate bitumen economic contingent
resources – an increase of 13 percent. The
information from these independent evaluations
is supported by a great deal of data, including
thousands of kilometres of seismic data and a
high number of well penetrations.
Our proved bitumen reserves, also based on
independent evaluations, grew from 866 million
barrels at year-end 2009 to 1,154 million barrels at
year-end 2010, an increase of 33 percent.
totAl 2010
diVidENd:
80¢
pEr commoN
shArE
These numbers – both proved reserves and
contingent resources – reflect the high quality of
our assets and the great work being done by our
teams. for the company as a whole, the increase
in our reserves, combined with highly competitive
proved finding and development costs* for 2010
of $3.65 per barrel of oil equivalent confirms the
wealth of opportunity we have on our lands.
CoMMiTTeD T o TeChnoL ogY
DeVeL o pMenT
As part of our business plan, we have committed
to implement at least one new commercial
innovation each year. We have more than 50
research and development projects underway at
any given time – about three-quarters of which
should result in environmental improvements.
pR o gResseD o uR enViR o nMenT aL
op poRTuniTY FunD
We committed to invest in three new
opportunities in 2010, bringing the number of
current environmental investments to seven.
The fund invests in companies and external
research groups developing emerging or early-
stage technologies that focus on water treatment
and management, energy efficiency, alternative
energy, emissions reduction, environmental
remediation and land disturbance mitigation.
Information about how to apply is on our website.
*Without changes in future development costs. See our
Additional Advisory on page 132.
25 · 2010 YE AR IN REVIEW · CENOVUS 2010 ANNUAL REPORT
Re aCheD R oYaLTY pa YouT a T Fos TeR CReek
oiL is o uR gR oW Th DRiVeR
In february 2010, our foster Creek project became
Alberta’s largest producing SAGD project to reach
payout for royalty purposes, which means higher
royalties are now paid to the government. This
milestone reflects foster Creek’s strong financial
and operational performance. foster Creek started
as a pilot project in 1996 and, in 2001, became the
first commercial SAGD project in the industry.
aCCeLeRa TeD e xpansions a T ouR MaJoR
sagD oiL sanD s pR oJeCT s
Foster Creek In September 2010, we received
regulatory approval to build three new expansion
phases (f, G & H) at foster Creek. Current
gross production capacity at foster Creek is
120,000 barrels per day, and each one of the three
phases is expected to add 30,000 gross barrels
per day, bringing total production capacity
up to 210,000 gross barrels per day. Work on
phase f is underway.
Christina Lake We’re advancing expansion
phases C and D at Christina Lake, which received
regulatory approval in 2008. We continued
construction of phase C in 2010 and began
constructing phase D. Phase C will add about
40,000 barrels per day of gross production
capacity with first production expected in Q3 of
2011. Phase D will also add about 40,000 gross
barrels per day of production capacity with first
production expected in 2013. We expect to bring
these phases on stream at an industry-leading
capital efficiency of about $22,000 per flowing
barrel. These two expansions will bring the
production capacity to 98,000 barrels per day on
a gross basis from its current 18,000 barrels per
day. We’re currently awaiting regulatory approval
for three more expansion phases (E, f & G), which
would add an additional 120,000 barrels per day
of gross production capacity.
BR ou ghT T W o eMeR ging oiL s anD s
pR oJeCT s CL oseR T o DeVeL opMe nT
narrows Lake In June 2010, we applied for
regulatory approval of a project at Narrows Lake,
located northwest of our Christina Lake project.
As part of that application, we have consulted
with the communities located near the project to
explain our plans. Narrows Lake will be developed
in phases up to a gross production capacity of
about 130,000 barrels per day. The application is
the first commercial project to include the option
to use SAP, a solvent aided process that increases
oil recovery.
grand Rapids We’re taking steps to develop a
future oil sands project in the Greater Pelican
Region, about 300 kilometres north of Edmonton.
In December 2010, we received regulatory
approval for a SAGD pilot in the Grand Rapids
formation. Drilling of the SAGD well pair is
complete, and in late 2010 we began injecting
steam into the formation. If the pilot is successful,
we plan to file a regulatory application for a
180,000 barrels-per-day commercial operation.
Bor e alis region
includes Telephone Lake
and other emerging projects
Technology used: sagD(1)
northern alberta
gre at er pelican region
includes pelican Lake Wabiskaw as well as
grand Rapids and other emerging projects
Technology used: polymer flood and sagD
northern alberta
chr istina l ake region
includes Christina Lake* as well as narrows
Lake* and other emerging projects
Technology used: sagD and sap(2)
northern alberta
Foster creek region
includes Foster Creek* as well as
emerging projects
Technology used: sagD
northern alberta
weyBu rn
Technology used: enhanced oil
recovery using Co2 sequestration
Weyburn, saskatchewan
We also have natural
gas and conventional oil
properties across Alberta
and southern Saskatchewan.
wood river reFin ery*
Roxanna, illinois
Borger reFinery*
Borger, Texas
*joint owner with Conocophillips
(1) steam-assisted gravity drainage
(2) solvent aided process
“We’re excited about the way we’re able to transfer
knowledge from one area to another. We’re applying
horizontal drilling and completion techniques from
our Saskatchewan, Lower Shaunavon and Bakken
developments to our Drumheller, Brooks North and
Langevin oil development programs.”
KEVI N KEL LY
TE A M LE A D , DR UMHELLER /BOYER
D eVeL op eD MuLTi- Ye aR gR oW Th pL an FoR
peLiCa n L ak e WaBi ska W
We have plans for significant growth of our
existing Pelican Lake Wabiskaw production as
we expand our polymer enhanced oil recovery
project. Our multi-year growth plan involves
more than doubling existing production to
40,000 to 50,000 barrels per day.
Mai nT ai neD a s TRo ng
Fin a nCi aL posiTi on
Both our debt to capitalization ratio of 26
percent and debt to adjusted EBITDA ratio of
1.2 times were at or below the low end of our
target ranges. Our cash flow was strong in 2010
at $2.4 billion and aligned with our expectations.
The majority of the cash required to fund our oil
sands growth is generated by our conventional
oil and gas properties. In 2010, these properties
contributed about $1.3 billion of operating cash
flow in excess of the capital spent on them.
e xpL oReD shaun a Vo n anD Bakk en FoR
n eW op poRTun iTi es
Our Lower Shaunavon and Bakken medium and
light oil assets in Saskatchewan are early stage
development opportunities for Cenovus. We had
25 wells producing at year-end 2010 with plans to
drill an additional 36 horizontal wells in the area in
2011. We anticipate production at the end of 2011
could reach 5,700 barrels per day.
opTiMi zeD CoaL BeD MeThane (C B M)
pR oDuC Ti o n FR oM e s TaBLi sheD shaLL oW
gas o peRa Tio ns
In 2010, we undertook a 900 well recompletion
program in our shallow gas operation to further
assess CBM potential on our lands. Total CBM
production from our Brooks and Langevin
properties was approximately 30 MMcf/d from
about 1,400 recompleted shallow gas wells.
The long-range plan calls for over 6,500 CBM
recompletions in existing shallow gas wellbores.
grEw oil sANds
productioN by
33%
oVEr 2009
CENOVUS 201 0 A NNUA L REPO RT · 2 01 0 Y E A R I N RE VI EW · 26
“We’re a company that
follows through on our
commitments.”
ADRI AN MI TCHE LL
RE SERVOIR A NA LYST
D iVe s TeD no n-C oRe ass eT s
In 2010, we sold some non-core assets in
southeastern Alberta and southwestern
Saskatchewan for net proceeds of $156 million.
Our total divestitures for the year were $307
million. As part of maximizing shareholder value,
we continually look to improve our asset base and
sell non-core assets as long as market conditions
are favourable. We believe it’s good business
practice to sell assets that aren’t part of our core
business and use those funds to invest in assets
that are in our area of focus.
our commitmENts:
rigorous
rEspEctful
rEAdy
“I’m really proud of the focus we have on developing
technologies that will reduce the impact our operations
have on the environment even further.”
SUB ODH GUPTA
TE CHNOLOGY ENHANCEMENT ADVISOR
OP ERATO R ADJUSTI NG VALVES AT T HE
W EYBU RN f AC I LI TY
CeLeBRa TeD TenTh an n iVeRsaRY
oF ouR WeYBuRn C o 2 pR oJeC T
In September 2010, we celebrated the tenth
anniversary of our Weyburn carbon dioxide
(CO2) enhanced oil recovery project, which uses
technology to improve both oil recovery and
our environmental performance. Since CO2 was
first injected into the reservoir in 2000, more
than 16 million tonnes of CO2 have been stored
at Weyburn, which otherwise would have been
vented into the atmosphere. The Weyburn oil
field is located in southern Saskatchewan.
ToL D ouR s ToRY
Presenting to investors and government officials,
doing media interviews, meeting with community
leaders, groups and landowners, working with
Aboriginal communities, and communicating with
our employees – we remain committed to telling
our story to all our stakeholders to help them
understand our company, the quality of our asset
base, the strength and expertise of our teams, our
solid financial position and our commitment to
operating safely and responsibly.
WED GE WELLS AT fOSTER CREEK
AS PART Of TELLIN G O UR STORY , WE C RE ATE D ADS
IN THE f A LL Of 20 1 0, fOC USE D ON THE VAL UE O IL
AND N ATURAL GA S B RI NG TO OUR LI VE S
SET Of ADS , WHI C H L A UN CHED I N E ARLY 20 11 ,
IL LU STRATE W HAT A SAGD O PERAT IO N LO OK S L IK E
TH E A DS C AN BE V I EWED O N OUR WE BS I TE
. A SE CON D
.
.
27 · 2010 YE AR IN REVIEW · CENOVUS 2010 ANNUAL REPORT
es TaB Lis heD L o ng-TeRM agReeMenT WiTh Co nkLin C
oM MuniTY
We signed a long-term agreement with the
Aboriginal community of Conklin, which is
located less than 20 kilometres from our Christina
Lake project in northern Alberta. The agreement
will provide mutual benefits for as many as 40
years and outlines our commitment to working
and engaging with the Conklin community on the
following matters:
> providing benefits such as employment,
community investment, business development,
education and training
> determining how we’ll engage with the
community as our projects grow and how we’ll
work together to address any issues that arise
> protecting the environment and protecting
Christina Lake
> providing financial and other resources that
will help Conklin residents adapt to change in
their area
CENOVUS VICE-PRESIDEN TS JO IN T HE C ON KL IN
RESOURCE DEVELO PM EN T ADVI SORY C OM M ITTEE
TO SIGN A LONG- TERM AG REEME NT WITH THE
COMMUN ITY Of C ON KLI N.
aDV anCeD C oRpoRa Te Resp on siBiLiTY a T
Ceno Vus: neW poLiCY, neW Me as uRe s
MaDe a DiF FeRenCe in The C oM MuniTie s
WheRe We LiVe anD W oRk
At Cenovus, corporate responsibility (CR) is
integrated into the way we do business. In
2010, we created a policy that reflects our
company and our commitment to CR. It sets
out our guiding principles relating to leadership,
corporate governance and business practices,
people, environmental performance, stakeholder
and Aboriginal engagement, and community
involvement and investment. Additionally, in July
2010, we released our first set of CR performance
measures. These measures set a firm foundation
for future public reporting on our company’s
non-financial performance. In developing these
measures we used the Global Reporting Initiative
guidelines as a framework for reporting and have
begun to align our performance metrics with the
standards set out by the Canadian Association
of Petroleum Producers’ Responsible Canadian
Energy program.
Company giving In 2010 Cenovus worked with
427 organizations, providing both monetary and
in-kind assistance in the communities where
we live and work. We also became an Imagine
Canada Caring company, which means we give
one percent of our pre-tax profits to charitable or
non-profit organizations. In 2010 that resulted in
$13.5 million in donations.
employee giving Our employees contributed more
than $3.2 million (including the company match)
through our annual giving campaign, matching gifts
and volunteer programs. The money benefited
nearly 700 charitable organizations across Canada.
During the annual campaign, which runs every
October, employees designate their donation
amount to charities of choice, with Cenovus
matching donations dollar for dollar.
“It was great to have the Executive Team
visit us in the field.”
ART L AURI N
PRODUCT ION COO RDI NATOR
THE E X ECU TIVE TE AM VI SI TS O UR P E L IC AN L A K E SI TE
CENOVUS 201 0 A NNUA L REPO RT · 2 01 0 Y E A R I N RE VI EW · 28
AT CENOVUS WE BELIEVE IN BEING A PART Of THE
. IT ’S
COMMUNITIES WHERE WE LIVE AND WOR K
ABOUT BEING INVOLVED AND MAKING A POSITI VE
DIffERENCE INCLUDING COMING TOGETHER IN THE
SPIRIT Of GIVING TO DONATE GIf
AND TEENS DURING THE HOLIDAYS .
TS fOR CHILDREN
Ce noVus n aMeD T o DoW Jo nes
sus Tain aBiLiTY inDe x (DJs i) anD
CaRBo n Dis CLos uRe Le aDeRs hip inDe x
The DJSI North America Index recognizes
companies from Canada and the United States
for their sustainability performance. Companies
are selected based on an annual assessment of
economic, social, environmental and corporate
governance performance. The Carbon Disclosure
Leadership Index recognizes companies for their
leadership in the reporting of greenhouse
gas emissions.
totAl rEcordAblE
iNjury frEquENcy
lowErEd by
15%
es TaBLi sheD L o ng-TeRM agRe eMenT WiTh Con kLin C
oMMun iTY
MeeT ouR eMpL oYees
The people of this company embody the spirit of Cenovus.
Rigorous in their commitment to smart resource development.
Respectful in their commitment to doing right by the
environment and communities where Cenovus operates. Ready
in their commitment to embracing fresh thinking and new ideas.
KNOWLEDGE + DEDICATION = the right people
Cenovus is
an excellent place
to work. I get
the opportunity
to work with
great people
on innovative
projects.
naThan hYLT on
I don’t know
what the next
year will bring
but here’s hoping
that year two will
be as positive and
successful.
It’s really great to work at a
company that values innovation and
embraces new ideas as part of our
everyday approach to doing business.
nasseR aW aDa
It’s exciting to be
part of a company
with both an
established history
and track record
and yet a totally
new identity, new
culture, new way of
doing things.
It’s been
a rewarding
experience
introducing our
local stakeholders
to our company
and our plans.
TReV oR BoRs
CaM kopanskY
It’s important to me to work
for a company that takes safety so
seriously.
I come to
work every day
knowing that
people rely on
us for the oil and
natural gas we
produce.
ChRis oLiVeR
Helping to
build a new
company has
been an exciting
experience.
Jason sWiTzeR
There’s such
a strong spirit of
camaraderie at
Cenovus.
kiM Yee
CoLe BR osT
Liz Young
29 · MEET OUR EMPLOYEES · CENOVUS 20 10 ANNUAL REP ORT
MeeT ouR eMpL oYees
Trevor Aadland / Ali Abbassi / Jason Abbate / Yasmin Abdul / Phillip Abraham / Phil Abrey / Nicole Abs / Michalene Adair / Aaron Adam / Jennifer Adams / Stewart Adams / Jamie Agnew / Annie Agustin / Rhonda Aiello / Abayomi Akande / Jennifer Alaric / Sheila Albon / Gary Alden / Everett
Alderdice / Neil Aldridge / Jim Aleman / Michael Alessio / Renee Alessio / Andell Alexander / faisal Alimohd / Travis Alkier / Courtney Allan / Denise Allan / Michael Allan / Dale Allen / Roberto Allende-Garcia / Douglas Allin / Cindy Alpaugh / Brett Altwasser / Vernon Alvis / Jason Aman / Jon
Amerl / Kim Amirault / Giuseppe Ammirati / Arthur Amyotte / Ligen An / Andrea Anderson / Brent Anderson / David Anderson / Gary Anderson / Judy Anderson / Michael Anderson / Richard Anderson / Timothy Anderson / Todd Anderson / Ken Andres / Edith Andrew / Mark Andrews / Tamer
Antar / Gwenda Anweiler / Kimberly Appleby / John Arcovio / Lesley Arnett / Caroline Arnieri / Royce Arnott / Aaron Arsenault / Julian Arsenault / Joel Arthurs / Michael Arychuk / Abbas Arzpeyma-Nemati / Shane Ashby / Marijane Ashforth / Derrick Ashworth / Andrew Asplund / Karen Asselstine
/ Theodore Assie / Laverne Atkinson / Tony Atwood / Lawrence Auger / Lenny Auger / David Austin / Mark Austin / Nasser Awada / Brett Aylwin / Karmyn Ayn / Cole Babey / Wade Bachur / Erica Back / Tracy Bader / Mohammad Bagheri / Mohammad Bahadori / Robert Baillargeon / Brian Bain /
Arnold Baker / David Baker / Evan Baker / Nadia Baker / Rawleen Baker / Robert Baker / William Baker / Colin Ball / Dale Ball / Susan Ballendine / Christopher Ballesteros / Wayne Bamber / Peter Bandola / Chad Barber / Brenda Bardell-Resch / Jason Bardick / Ryan Bardick / Paul Barker / Sandra
Barker / Debra Barnett / Arnold Baron / Robert Baron / Courtney Barr / Marc Barrette / Dallas Barrie / Stuart Barrie / Shirley Barron / Bradley Barrow / Darcy Barry / Jamie Barsness / Connie Barteaux / Lori Barth / Michele Barth / Ronald Bartlett / Isabella Baslios / Barbara Bateman / Keith Bateman
/ Wayne Bateman / Darwin Bateyko / Kelly Bauman / Kelvin Bauman / Vincent Bax / Susan Bayly / Elizabeth Bayrak / Richard Beale / Leslie Beard / Dale Beaton / Aime Beaulac / Lori Beaulieu / Theran Beaulieu / Javier Becaria / Jessica Beck / Robert Beckett / Jeffrey Beckford / Jacqueline Beckie /
Niel Beckie / Kenneth Beierbach / Jeremy Belair / Catherine Belanger / Dale Belbin / Lloyd Belcourt / Matthew Belitsky / Carrie Bell / Diane Bell / Kelly Bell / Scot Bell / Irene Belthazar / Marisol Ben / Corey Beniuk / Jason Beniuk / Jeffery Beniuk / David Benn / Greg Benzon / Corey Berg / Grant
Bergos / Alan Berkiw / Maria Bermudez / Stephen Bernard / Mark Berrett / Tanya Berry / Leona Bertagnolli / Shawna Bertin / Julie Bertram / Mark Bertrand / Edward Bertschi / CherylLyn Best / Monica Betancourt / Tracy Bialowas / Ovidiu Bibic / Cody Biech / Alice Bienia / Dean Bierkos / Jo-Ann
Biggs / Mark Bilozir / Mark Bilyk / Paul Binassi / Brandi Biollo / Chad Biollo / Lori Birdsell / Jillian Birnie / Bradley Bischoff / Amanda Bishop / Cassandra Bishop / Tyler Bishop / Tom Bissell / Darin Bitz / Christopher Blackwood / Ryan Blais / Trevor Blake / Deborah Bland / Connie Blatch / Adam
Blazenko / Brenda Blazenko / Michael Bleackley / Blake Bloor / Brenda Bloski / Phil Blower / Glen Blythe / Leslie Boc / Scott Bodnar / Kerry Bohnet / Denis Boivin / Blaine Bolen / Kenneth Bolstad / Kevin Bolton / Glen Bonogofski / Kyle Boon / Rupam Bora / Bryan Boratynec / Albert Bordeleau /
Gail Bordeniuk / Robert Borgen / Joseph Borras / Trevor Bors / Anna Bortolotto / Deborah Bosse / Moira Botham / Roger Boucher / Elisa Bourget / Crystal Bowen / James Bowman / Matthew Bowman / Michael Bown / Wayne Boylan / Rosana Bracho / Ian Braconnier / Darcy Bradley / Hugh Bradley
/ Leanne Bradley / Kim Brady / Sean Brady / John Brannan / Chad Branvold / Darlean Brasic / Gilles Brazeau / Jessica Brears / William Brears / Edmond Breland / Ryan Bremer / Michael Brennan / Lynda Briand / Carol Briceno / Stephen Brink / Claudine Brinston / Debora Brisson / Danielle Broadwell
/ Glenn Bromley / Pierre Brosseau / Cole Brost / Benjamin Brown / David Brown / Diane Brown / Gary Brown / Kevin Brown / Mary Brown / Terry Brown / Wade Brown / Jason Browne / Jamie Bruinsma / Jessica Bruneau / Edlyn Bruni / Donald Bryan / Nickole Bryan-Johnson / James Bryden / Daniel
Bryson / Rodney Buchan / Christopher Buchanan / Brad Buckingham / Kent Buckingham / Dean Buckosky / Joseph Bueckert / Brent Bull / Stjepan Bulmer / Michael Bumstead / Candace Bundus / Tara Bunes / Jamie Bunka / Alfred Burk / Dean Burkart / Deborah Burke / Thanh Burns / Geoffrey Burrowes
/ Janet Burton / Cindy Busch / Randi Busenius / Heather Bush / Chad Buteau / Cayley Butt / David Butterwick / Brian Bylo / Jennifer Byrnes / Amanda Cabaj / Bernadette Cadden / Rex Cagas / Jerry Callaghan / Jenni Calvert / Cremilde Camara / Cambridge / Anna Cameron / Lauressa Cameron /
Michael Cameron / Earl Campbell / James Campbell / Patrick Campbell / Ryan Campbell / Sandra Campbell / Christian Canas / Patricia Cancade / Carissa Caouette / Matt Cardall / Lance Cardinal / Donna Carey / Andrew Carleton / David Carley / Ercidio Carli / Linda Carr / John Carson / Nancy
Carson / Paul Cary / Janne Cash / Teresa Cassetta / Miguel Castillo / Nory Cayago / Brian Celaire / Dan Cesario / Renee Chabeniuk / Daniel Chambers / Andy Chan / Betty Chan / Chong Chan / Edward Chan / Tammy Chan / Wai Chan / Steven Chang / Giselle Chao / Colin Chapman / franklyn
Charles / Dawn Chau-Lam / Brady Cheek / Qiaozhi Chen / Zhen Chen / Ryan Cherniwchan / Stacy Chessall / Daniel Cheung / Joseph Cheung / Winifred Chew-Semple / Michelle Cheyne / Harbir Chhina / Hicham Chibl / Katharine Chidley / Alberta Chikmoroff / Julie Chim / Leonie Chin / Tom Chin
/ frank Chinski / Lisa Chinski / Beth Chisholm / Stephen Chiu / Robert Chorney / Lawrence Chou / Eva Chow / Roger Chow / Sherry Chow / Ruth Christensen / Brad Christian / Gordon Christian / Duane Christiansen / Bradley Christie / Sandy Chu / Kyle Chudyk / Linda Chueng / Darrell Church /
Jeremy Church / Mark Churla / Manolito Cillo / Michael Clark / Kelley Clarke / Robert Clarkson / Mylene Clavette / Cameron Cline / Cindy Cloutier / Melissa Clow-Gordon / Brenda Coates / Adam Cocks / Donald Cocks / Michael Cody / Christopher Colantonio / Kevin Cole / MaryJane Cole / Eric
Collins / Adam Colosimo / Taylor Comb / Peter Conacher / Brian Connolly / Cindy Connolly / Roger Connolly / Whitney Connolly / Joyce Conrad / Bradley Cook / Debbie Cook / Leighton Cook / Brandon Cooke / Kevin Cooke / Shane Cooke / Sherel Cooney / Cooper / David Cooper / Gordon
Copp / John Coppock / Joshua Cornet / Daniel Corriveau / Gregory Cosma / Stephen Costello / Allain Cote / Leanne Courchesne / Darryl Courts / Alan Cox / Robert Cragg / Robert Cragg / Ann Craig / Laurie Craig / David Craigen / Mitchell Crane / Tyson Craney / Robert Craswell / Ann Crawford
/ Colbey Crawford / Warner Crawford / Kelly Creasy / Darcy Cretin / Roger Crocker / Daniel Cronin / Lloyd Crosby / Colleen Crowe / Doug Crowe / Susan Crowley / Lucas Crutchfield / Sharon Culley / Ian Cully / Mirjana Curcic / Darren Curran / Reginald Curren / Thomas Currie / Darrell Curtis /
Will Cuthbert / Carl da Silva / Kyla DaCosta / Jana Dagsvik / Jeremy Daku / Lori Daley / Noemi Dani / Jacquelyn Daniels / Ryan Daniels / Darren D’Arcangelo / Christopher D’Arcy / Zachariah Darwiche / Amitava Datta / Victoria David / Adam Davidson / Derrick Davidson / Jefferey Davies / Laverne
Davies / Monique Davies / Theodore Davies / Joan Davis / Marie Davis / Stephen Davis / De Blasio / Susie De Giusti / David Deacon / Christopher Deakin / Joseph DeBeaudrap / Ann DeBoer / Bradley Decker / Debra Dedora / Lindsey DeGusti / Leanne Deighton / Terry Dejikhangsar / Gerald Del
frari / James Delaney / Rhona Delfrari / Sheri Delf-Smithson / Justin Dell / Richard Dembicki / Greg Demchuk / Mark Demchuk / Myles Denis / Ian Denney / Kevin Depner / Dustin Derkach / Kelly Derlago / Michael Dery / Christine Deschamps / Darlene Desharnais / Jason Desilets / Melissa Desjarlais
/ Rachel DeSouza / Rachel Desroches / Henry Desy / Gene Dethlefsen / Tracy Devitt / Amandeep Dhillon / Annette Di Palma / Everett Diamond / Carolina Diaz-Goano / Cheryl Dick / Geoff Dickinson / Jennifer Dickinson / Garry Didow / Leland Dierkhising / Bradley Diesel / Duane Diesel / Ling
Ding / Marsha Dixon-Robicheau / Derrick Dobrowski / Russell Dodd / Maria Dodsley / Wade Doering / Colleen Doering / Amanda Doggett / Patricia Doherty / Nicole Doig / Tamara Doige / Ross Dollin / Steve Donaldson / Gregory Donaldson / Heather Donauer / Dahai Dong / Debra Dorcas /
Charlene Dorey / Brent Dorval / Rene Dorval / Chad Doucet / Lynne Douglas / Michael Douglas / Cibele Dourado / Patrycja Drainville / Brenda Draper / James Dribnenki / Kenneth Dryden / Lili Du / Marc Dubord / Marc Dubrule / Roger Ducharme / Marcel Duchesneau / Thomas Dueck / Katharina
Duford / Olga Dumitrache / Dave Duncan / Dallas Dundas / Wesley Dundas / Marilyn Durant / Joseph Dusseault / Peter Duthie / Kelly Dutnall / Karanvir Dutt / Andrew Dutton / Kirk Duval / Clarence Dyck / Elaine Dyck / Erwin Dyck / Russell Dyck / Victor Dyck / Heather Dyer / Nicole Dykstra /
Joyce Dyson / Kerry Dyte / Jeff Ealey / Leslie Eckert / Micah Eckert / Rodney Eckes / Bonnie Edmonds / Andrew Edmunds / Kathleen Edmunds / Robert Edwards / Lloyd Ehmann / Gabriele Ehnes-Lilly / Jennifer Eisenberg / Nolan Eisnor / James Ekelund / Mohamed Elashry / Tylor Ell / Christopher
Elliott / Katherine Elliott / Michael Elliott / Norman Ellis / Timothy Ellis / Keith Ellwood / Shamel Elsayed / Lee Emms / Leslie Emms / Grace Eng / Michael Engler / Randy Engler / Ian Enright / Shawn Epp / Tamar Epstein / Toby Ergang / Devan Erickson / Blaine Erne / Rita Erven / Brent Espersen /
Luigi Esposito / Phillip Esslinger / Timothy Etcheverry / Audrey Etherington / John Eubank / Donald Evans / Ryan Evanson / Stephen Ewart / Kelly Ewasiuk / Wade Ewen / Jason Ewing / Lawrence fabbro / Steve fader / Greg fagnan / Wayne fairbrother / Judy fairburn / Bradley falez / Ali falsafi /
James fann / Ian farrell / Jaclynn farrow / Olugbenga fasesan / Shadi fattahi / Paul faucher / William faulkner / Stephanie fawcett / Lynette featherstone / Bonnie fedoration / Thomas fedoruk / James fehr / Cindy feldman / Shawn fellner / Danielle fendelet / Yongyi feng / Ryan ferdais / Colin
ference / Brian ferguson / Kenneth ferguson / Tanis ferguson / Tracy ferguson / Kevin ferreira / Pierre feser / Dario ficaccio / Mark fieger / Dorothy filiatrault / Brett filkohazy / Earl finch / Scott findlay / Kelly finigan / Lorne firkus / Colin fischer / Gary fiselier / Ernest fisher / Ryan fisher /
Richard fitzel / Cara fitzgerald / Gail flaherty / Grant flaig / Kelly flaig / Sherie fleming / Beth florio / Ellen f ong / Kelly forbes / Kyle forbes / Michael forbes / Allan ford / Devon ford / Glenn forde / Tyrell foreman / Julien fortier / Andre fortin / Nancy foster / Shane fournier / Patricia fowler
/ Daniel fradette / Roberts frampton / Jody francis / Kathleen franco / Jason francoeur / Aaron frank / Lloyd franklin / Roberta frankow / Jack fraser / Jennifer fraser / Shaun fraser / Darren frederick / Karen freeborn / Natasha freedman / David freeman / Larry freeman / Tammy freeman / Kyle
freimuth / Kenneth friesen / Teresa friesen / Dexter froehlich / Denise froese / Eli frolov / Adam fry / David fryett / Murray fuerst / Shane fuson / Jeff Gaberel / Ian Gabouda / Kyle Gaetz / Kelly Gagne / Clarke Gagnon / Kody Gagnon / Chad Galbraith / Paula Galbraith / Daniel Galipeau / Glenn
Galipeau / Micheal Galipeau / Marie Gallant / Jeremy Gallop / Debbie Gammon / June Gan / Hong Gao / Robert Gardner / Chad Garland / David Gartshore / Nancy Gauthier / Sherlyn Gavronsky / Crystal Geiss / Eric Geppert / Glenroy Gerald / Janice Germain / Dustin Gervais / Kelly Gervais /
Michael Gibbs / John Gibson / Kathy Gibson / Travis Gieck / Barry Gilchrist / Brayden Gilewicz / Baljinder Gill / Gurtej Gill / Randolph Gillard / Stanley Gillard / Kenda Gillespie / Keeling Gin / Joel Girard / Simon Gittins / Corina Gladney / Robert Glass / Kimberly Glennie / Charles Gobin / Travis
Godfrey / Adam Goehner / David Goldie / Todd Gondek / Gaspar Gonzalez / Darrin Goodheart / Suzanne Goodwin / Cecil Gordon / Heather Gordon / John Gordon / Jennifer Gorman / Lance Gosselin / Jason Goudie / Cathryn Gough / Patricia Goulbourne / Bailey Gould / Sabrina Gould / Marc
Goulet / Rene Goulet / Peter Goumans / Colin Gouthro / Andrew Graham / Conrad Grams / Christopher Grant / Michael Greaves / James Grecco / Dale Green / Naomi Green / William Green / Dale Greene / Robert Greenop / Alexander Greenshields / Brent Greenstein / Allan Greeves / Lisa
Gregory / Paul Gregory / Kent Greig / Susan Grey / Brent Grieve / Mary Grieve / Jason Griffiths / Jason Grimard / Brian Griswold / Brett Guenther / Douglas Guild / Majahana Gumede / Gurdip Gundara / Subodh Gupta / Ritu Gurjar / Dwayne Gurski / Philip Gwozd / Cheryl Gwynn / Gary Hack /
James Haddad / Chad Hadler / Kenneth Hadley / Sheldon Hagen / David Hager / Brian Hagerman / Thomas Haggart / Cindy Halford / Cindy Halim / Cory Hall / Tylor Halonen / Blair Halter / Nicole Haltman / Alison Halyk / Chris Hamel / Lucie Hamel / Donald Hamilton / Kristy Hammermeister /
April Hammond / Jaw Han / Lyle Hanch / Tanya Hancock / Lee Hannaford / Liz Hannah / Lesley Hansen / Bradley Hanson / Ryan Hanson / Dhugal Hanton / Leslie Hanton / Valerie Hardman / Danielle Hardy / Lisa Hardy / Robert Harper / Janet Harren / Murray Harrington / Richard Harrington / Daryl
Harris / Eugene Harrison / Jason Harrison / David Hart / Lucy Hart / Marianne Hart / Amanda Hartman / Robert Harty / Eugene Harwood / Christopher Haskell / Douglas Haskell / Dave Hassan / Heather Hastie / William Hastie / David Hastings / Hatch / Garrett Hatch / Russel Hatch / Robert Hauca
/ Murray Hauck / Leslie Hauser / Alicia Hawkings / Ryan Hawkings / Dean Hawkins / James Hawkins / Christopher Hayes / Julia Haynes / Matthew Haysom / Micheal Hayward / Ronald Hazelwood / Dennis Hazzard / Wyatt Heard / Roger Hebert / Joel Heese / Kevin Heffernan / Allan Heidinger / Roy
Heise / Delvin Heller / Richard Hellmer / Gary Henault / Bradley Henderson / Kelly Henderson / Shelly Henke / Kurt Hennig / Dawn Henry / Michael Henschel / Trudy Hergert / Jordan Herle / Brent Herman / Kurt Hermann / Jose Hernandez / Orlhay Hernandez / Candice Heron / Dean Herriman /
Wayne Hertz / Lucie Herzig / Colin Hibbert / Stephen Hicks / Laura Hider / Laurie Hilkewich / Shane Hillaby / Zepporah Hinton / Stacy Hittel / Ki-Tat Ho / Shawn Hobman / Jeffery Hodder / Tom Hodgins / Corinne Hoebers / Steven Hofer / Julie Hoff / Elise Hoffman / Matthew Hoffman / Darren
Hofmann / Larry Hofstetter / Tammy Hogan / William Hogue / Robert Hohls / Yorka Holl / Stephen Hollingshead / Ryan Holmes / Nathan Holsapple / Patricia Holtan / Norman Holtz / Morris Holuk / Claire Hong / Hai Hong / Steven Hoof / Lorna Hopkins / Landon Hopp / Logan Hopp / Glenn
Horiachka / Christopher Horkoff / Loreli Hornby / Candice Horne / Tracey Horne / Todd Horsman / Renita Hoskins / Ryan Hoskins / Karin Hossack / Jennifer Houssin / Bonnie Howard / Michael Howard / Christopher Howe / Robert Howe / Kathy Howell / Mark Howell / Randy Hoynick / Glen
Hrycauk / Trevor Hrycay / Yumin Huang / Kenneth Huard / Christopher Huber / David Huber / Gregory Huber / Warren Huber / Beverly Hudjik / Jennifer Hudson / John Hudson / Michael Hudson / Joel Hughes / Tim Hughes / Blaine Hujber / Susan Hume / Carmelle Hunka / James Hunt / Ashlee
Hunter / Hilary Hurst / Bradley Hurt / Brent Huynh / Nathan Hylton / Laina Hynes / Sheena Hynes / Chad Hyshka / Kevin Hyslop / Sheldon Ibach / farhang Ighani / Tara Ignacio / Pedro Ilomin / Cheryl Inkster / Jennie Innendorfer / Gamze Ipek / Earl Irwin / Jill Isaak / Troy Ivanics / Dustin Jack /
William Jack / Piers Jackman / Antonio Jackson / Kelly Jackson / Kyle Jackson / Sheldon Jackson / Tom Jackson / Rebecca Jacksteit / Sandra Jacob / Michelle Jacobsen / John Jacques / Lynda Jager / Charlene James / Darren James / Jason Jamieson / Lester Janke / Lyle Jans / Nishikant Jawne / Carrie
Jeanes / Kenneth Jensen / Peter Jensen / Tammy Jensen / Jennifer Jessome / Jeffrey Jeworski / Dana Jia / Gino Jimenez / Michael Jin / Michael Jin / Norman Jodoin / Sibu John / Stephanie Johner / Brian Johnson / Chad Johnson / Leslie Johnson / Linda Johnson / Michael Johnson / Steve Johnson /
Terry Johnson / Johnston / Brad Johnston / Derek Johnston / George Johnston / Michelle Johnston / Nathanial Johnston / Susan Johnston / Tony Johnston / Gary Joncas / Colleen Jones / Janet Jones / Tyler Jones / Nicolaas Jonk / Donald Jordan / Richard Jordan / Kurt Jordheim / Bryan Jory / Peter
Joziasse / Julita Junio / Brent Kadler / Joleen Kadler / Lee Kadutski / Paul Kahler / Cody Kallis / Leonard Kampel / Patricia Kananda / Justin Kangarloo / Renae Kapala / Brad Karaja / Charissa Karaszkiewicz / farahnaz Karimian / farida Karimova / Milosz Karpinski / Bradley Karpuk / Almas Kassam /
Rose Kassamali / Arron Kaura / Nilesh Kawa / Deanna Kealey / Michael Kealey / Bernard Kelly / Brandon Kelly / Darren Kelly / Kevin Kelly / Corrina Kennedy / Patrick Kenney / James Kenny / Shawn Kergen / Stephanie Kerluck / Kyle Keyowski / Geoffrey Keyser / Isaac Khallad / Kimberly Khoury /
David Kielstra / Stuart Kilfoyle / Lori Kimoff / Anling King / Margaret Kinsella / Steven Kipta / Wayne Kirk / Benjamin Kis / Nora Kish / Stephen Kisman / Paul Klaassen / William Klassen / Tyler Klatt / Chad Klein / Timothy Klone / Jody Klotz / Sheila Klutz / Dean Kmech / Gordon Knaus / Paul Knight
/ Shelley Knight / Daniel Knipstrom / Lyle Knowlton / Ronald Knox / Richard Kobetitch / Barry Koch / Russell Koehler / eorge Kohn / Michael Kokorudz / Annette Kolisnyk / Andreas Koller / Garry Kolodychuk / Jeannette Koluk / Sheldon Komodowski / Cameron Kopansky / Brett Kopeck / Jerry
Kopeck / Kenneth Kopeck / Carey Kopp / Andrea Korencik-Butler / Clarence Korpan / Timothy Koskowich / Richard Kotowicz / David Kowalchuk / Janelle Kowalchuk / Norman Kowalchuk / Timothy Kowbel / Kenneth Kozak / Camille Kozar-Crittenden / Jack Kraft / Wade Krauss / Alan Krawchuk /
Bradley Krawchuk / Mark Kriaski / Ross Krill / Kerry Kryzanowski / Romuald Kuc / Patricia Kudelik / Patricia Kuhn / Keshava Kumar / David Kunetsky / Philip Kunka / Daniel Kunstmann / Janet Kunstmann / Darwin Kuttnick / Douglas Kuwahara / Barton Kwochka / Randy Kyle / Dinh La / Jocelyn Labonte
/ Julius Laboucan / Chad Lacina / Christopher Lackey / Makstr Lacoursiere / Krystal Laferriere / Donald Lafond / Philip Lafond / Patricia Lafreniere / Shawnda Lahey / Kathryn Lahoda / Danielle Lajoie / Gregory Lakey / Amreen Lakhani / Luc Lalonde / Robert Lambe / Michael Lambert / Erin Lamb-
fauquier / Michelle Landry / Peter Landry / Russell Landry / frances Lang / Keith Lange / Emilie Langevin-Murray / Stewart Langner / Eric Laplante / Daniel Lapointe / Debra Lapointe / Elizabeth Lappin / Jeffrey Larsen / Lance Larsen / Kirk Larson / Rodney Larson / William Lathrop / Andrew Laturnus
/ Arthur Laurin / Kyle Lavallee / Shawnene Lavallee / Scott Lavalley / Chris Lawrence / Dean Lawson / Susan Lawson / Mark Laxdal / Brody Laybolt / Jason Lea / Diane Leach / Darryl Leason / Kirk Ledgerwood / Christi LeDrew / Robert LeDrew / Chrystan Lee Wah / Amanda Lee / Benjamin Lee /
Betty Lee / Christine Lee / David Lee / Irene Lee / Keith Lee / Reginald Lee / Ronny Lee / Shirley Lee / Tiffany Lee / Brent Leeb / Jeremy Leggatt / Sean Legge / James Leibel / Christian Leith / Chantelle Leliuk / Andre Lemay / Jean-francois Lemire / Colleen Leong / Irvin Lepp / Anne Lerner /
Ashley Leroux / Kelly Lester / Michael Lesyk / Stella Leung / Derek Lewis / Leslie Lewis / francis L’Henaff / Lionel Li / Gene Libke / Bernadette Ligocki / Melanie Lindholm / Warren Lindland / Carol Lines / Lonnie Lischka / Leslie Liska / Lori Little / Kun Liu / Xiaohuan Liu / Yamei Liu / Hanna Livak
/ Jack Livingstone / Tannis Liviniuk / Megan Lloyd / Elaine Loades / Terrance Lobe / Conrad Lockhart / Deanna Lodge / Jerry Loewen / Nanette Loewen / Peter Loewen / Susana Loewen / Matt Loggie / Jeffrey Lohnes / Tyrell Lohse / Kathy Lokinger / Milton Lokken / Jianying Long / Sonja Lonson
/ Michael Loo / Darin Lorenson / Darryl Lorentz / Shelley Louie / Andrea Louise-Martyn / Kenneth Lowe / Shirley Lowe / Christopher Lowes / Yvan Luciuk / Monica Ludwig / Samantha Lui / Keith Lukan / Jeremy Lumgair / Tammy Luong / Darlene Lynch / Holly Lynch / Jeffrey Lypka / Yvonne Ma
/ Ailsa MacDonald / Leanne MacDonald / Madeleine Macdonald / Robert MacDonald / Cara MacEachern / Jeremy Macht / Brae MacInnis / Craig Mack / Benjamin Mackay / Cheryl MacKenzie / Catherine MacKinnon / Donald MacLeod / Evan MacLeod / Jean Macnab / Cynthia MacQuarrie / Leilani
MacQuarrie / Sherry MacRae / Brent MacSween / Lorrie Madore / Jen-Ryan Magbanua / Benjamin Magnus / Colin Magnusson / Michael Maguire / Scott Maguire / Timothy Mah / Roland Mahe / William Maher / Adlai Majer / Benjamin Makar / Shannon Makinson / Nenad Maksimovic / Tyler
Maksymchuk / Zenin Malazdrewich / Erica Mallard / Kenneth Mallory / Jonn Malmqvist / Jules Malo / Mark Malouin / Kelvin Manastyrski / Sirish Mandapati / fred Mandel / Carmen Manning / David Mansfield / Brady Mapstone / Lisa Marchand / Clifford Marcotte / Robert Markle / Ross Markowski
/ Betty-Jane Marks / David Marks / Rick Marsden / Wade Marsh / Clement Marshall / Megan Marshall / Darryl Martin / Ivan Martinovic / Robyn Marttila / Michael Martynuik / Alice Martynychev / Patricia Maruschak / Shahbaz Masih / Dawneen Massinon / Stephen Mathezer / Jordan Matthews /
Ray Matthews / Rex Matthias / Darren Matvichuk / Doug Maurice / Wahidat Mawji / Christopher May / Gerry May / Kevin Mayer / Lawrence Mayo / Ojikeme Mbadiwe / Richard McAlary / David McArthur / Gordon McCaughey / Michael McClay / Scott McClelland / Allan McColm / Laurel
McCormack / Rose McCormick / Greg McCuaig / Heddy McCurry / Katherine McCutcheon / John McDonald / Stephen McDonald / David McDougall / Jeremy McDougall / Bradley Mcfadden / Brad Mcfarlane / Kenneth McGillivray / Michael McGrath / Bruce McIlroy / Robert McInnis / Shelley
McInnis / Jeffrey McIntosh / Sheila McIntosh / Thomas McKee / Rhonda McKinney / Kristi McKinnon / Reed McKinnon / Brian McLachlan / Denise McLaren / Barry McLaughlin / Ryan McLaughlin / Curtis McLean / Troy McLean / Steven McLellan / Donna McLeod / Lewis McLeod / Margaret McLeod
/ Stewart McLeod / Barbara McMeckan / Christopher McMillan / Heather McMillan / Leslie McMillan / Perry McMillan / Terri McMillan / Sandy McNabb / Malia McNamara / Janice McNeil / Shelley McNeil / Kevin McNutt / Jillian McPhee / Martin McPhee / Jessica McPherson / Neil McRury / Lana
Meaney / Kathy Medina / Dustin Meek / Stephen Meerman / Ross Melchin / Daniel Melody / Michael Messer / Bradford Metcalf / Wendy Metcalf / Paul Metz / Glenda Meyer / Paul Meyers / Patrick Michetti / Leonard Mickalyk / Mihajlo Mihajlovic / Hubrecht Mik / John Miles / David Milia /
Shylin Miljan / Corey Miller / Deanna Miller / Maureen Miller / Natalie Milligan-Bertin / Robert Mills / Patricia Milne-Davenport / David Minions / Audrey Mirlach / Adrian Mitchell / Brent Mitchell / David Mitchell / Jonathan Mitchell / Larry Mizzau / Delvin Moch / Vijya Modha / Stephen Moffat
/ Byron Moffatt / Emelyia Moghaddami / Dallas Mohagen / Kerrie Mohninger / David Moisan / Craig Molde / Carolina Molina / Gary Molnar / Lisa Molnar / Karen Montemurro / Ana Montes de Oca / Shari Montgomery / Christopher Moody / James Moon / Royden Moon / Judy Mooney / Pamela
Moore / William Moore / John Moorhouse / Anthony Moroney / Patricia Morris / Byron Morrison / Linda Morrison / Mirna Moscoso / Darla Moser / Boyd Mostoway / Lisa Motuzas / Suzy Moutinho / David Mudie / Ryan Mueller / frank Mueller / Jessica Mueller / Terry Mueller / Daniel MuirLaslo
/ Anamika Mukherjee / Erin Mullane / Kendra Muller / Richard Muller / David Mullin / Melissa Mullins / Jean Mulumba / Chandy Mung / Alexander Munro / Blake Munro / James Munro / Donald Munroe / Shane Munsch / Brendan Murphy / Calvin Murphy / Keith Murphy / Seamus Murphy / Sean
Murphy / Tara Murphy / france Murray / Alisha Musa / Dean Nagy / Eva Nagy / Jeffrey Nail / Paul Nayyar / William Neary / Trevor Neault / Robert Needham / Janice Neil / Stephen Neilson / Bente Nelson / Catherine Nelson / Jayson Nelson / Richard Nelson / Liudmila Netsvetnaya / Peter Neu /
Jeffrey Neufeldt / Jessica Neuls / Donna Newlands / Deirdre Newman / Karen Newman / James Newsome / frances Ng / Henry Ng / Jessica Ng / Charles Ngai / Daniel Nguyen / Denise Nguyen / Joseph Nguyen / Mary Nhan / Jared Nichols / Eric Nicholson / Scott Nicholson / Kathleen Nickless /
Edith Nielsen / Miranda Nielsen / Shelley Nielsen / Andrew Nimmo / Tanya Ninovska / Caroline Njage / Shane Noble / Holly Nofield / Raymond Noot / Stacey Norman / Glen Novak / Stacey Nowaczyk / Jodi Noye / Marcela Nunez / Calvin Nurmi / Timothy Nygaard / Ben Nzekwu / Amelia Oakley
/ Scott Obrigewitsch / Ann O’Byrne / Mario Ochoa / Brian Odell / Ivan Odland / Jason O’Driscoll / Timothy Ogryzlo / Jordan O’Hara / Craig Oke / Aaron Oland / Chris Oliver / Marletta Oliver / Kurtis Olney / Brent Olsen / Dennis Olsen / Dennis Olsen / Kevin Olsen / Tracey Olsen / Wade Olsen
/ Bradley Olson / Daryl Olstad / Trevor Oltmanns / Phaik Ooi / Rodney Opperman / Grace Or / Richard O’Rourke / Lekan Osanyintola / Sandi Osmachenko / Mansour Osman / Jacqueline Osmond / Eric Overland / Matthew Overton / Catherine Oviatt / Lauree Owchar / Lara Owodunni / Jason
Pacholko / Kyle Pacholok / Darby Page / Dwight Pahl / Judith Paisley / Michael Palenchuk / Mark Palman / Brian Palmer / Eusebio Palmisano / Carl Palomaki / Carl Palomaki / George Pan / Sheila Pantuso / Jason Pao / Guy Parisian / Violet Parker / John Parkin / Dan Parliament / Terry Parnell / Coreen
Parsons / Randall Pasay / Geoffrey Paskuski / Ravinder Passi / Bhavesh Patel / Chirag Patel / Rashmikant Patel / Susan Patey LeDrew / Christopher Patey / Trilokeshwar Patil / Christopher Patterson / David Patterson / Aaron Patzer / Ajaykumar Pau / Brian Paulson / Journey Paulus / Matthew Pawliw /
Kathryn Payne / Darren Pearman / Shane Pearsall / Cassandra Pedersen / David Pedersen / Gary Pederson / Jason Pederson / Stephen Pella / Jennifer Pemberton / Keefe Pendleton / Jennifer Pendura / Xiaohua Peng / Kristina Penney / Randy Penny / Wayne Pennycook / Aaron Penton / Steve Penwarden
/ Clinton Peredery / Chris Perkons / Shawn Perrault / Brian Peterkin / Anthony Peters / Mitchell Peters / Terry Peters / Jeffrey Petersen / Stacey Petersen / Andrew Peterson / Ernest Peterson / Lowell Peterson / Robert Peterson / Troy Peterson / Veronica Petri / Leslie Petrie / Michael Petrock / Peter
Petrucci / Matthew Pettipas / Dwayne Pfeifer / fan Pfeifer / Martin Pflug / William Phee / Christie Phelan / Linda Phelan / Alana Phillips / Darren Phillips / Grant Phillips / James Phillips / Kevin Phillips / Linna Phu / Danny Picard / Leonardo Piedimonte / Ella Pierrot / Karen Pihl / Avery Pikowicz /
Robert Pilon / Simon Pinto / Trevor Pipke / Kenneth Pischke / Rob Pitchford / Shawn Pitre / Hughie Pittman / Michael Pittman / William Pittman / Ronald Plante / Brent Plato / Michael Plettell / Jayce Plouffe / Lee Poirier / Brenda Poitras / Joseph Poitras / Connie Pokiak / Andre Politylo / Kevin
Pollock / Robert Pollock / Ronald Polzen / Logan Popko / Glen Porter / Derek Potts / Veronica Potts / Thomas Power / Amit Prabhu / Riwan Prasatya / Claude Prefontaine / Michael Preston / Edward Preville / Carol Price / Elaine Price / Glenn Price / Tyler Price / Darren Prior / Gerald Prosper /
Jacob Prosser / Jerome Proulx / Ryan Proulx / Murray Pryor / Sharon Pudwell / Kirsten Pugh / Thomas Pugh / Steven Pullano / Scott Pura / Ann Purdy / James Purnell / Trad Pushie / Michael Putnam / Lin Qi / Ping Qiang / Jennifer Quach / Anthony Quan / Samuel Quantz / Sonia Quattrucci / Judy
Quinn / Kathryn Quintal / Samuel Quiring / Samuel Quiroga / Erin Radloff / Jason Raemer / Steve Raffa / Sharon Rainey / Gina Rajic / Lori Ramey / Ursula Ramsey / Gail Randell / Marc Ranger / James Rankin / Kevin Rappel / Kevin Rappel / Leah Rappel / Daryl Rasmussen / Kelly Rasmussen / Perry
Rasmussen / Adrian Rau / Corrine Rault / Eileen Rawlyk / Gideon Razemba / Matthew Read / Guy Reader / Nicole Redekop / Alexander Reed / Michelle Reed / Lisa Regan / floyd Regner / Alan Reid / Bryon Reid / Callie Reid / Collin Reid / Gwen Reid / Heather Reid / Vicki Reid / Paul Reimer /
Douglas Rein / Andrew Reinke / Shaida Remtulla / Alain Renaud / Wayne Resch / Jonah Resnick / Craig Reszel / Justin Reti / Joanne Rex / Wayne Reynolds / Rodney Rhodes / Grant Ribey / Allan Richard / Christopher Richard / Scott Richardson / Dean Riddell / Dean Riddell / Jason Riddell / Brendan
Rieder / Gerard Rieger / Helen Rignault / Robert Ringuette / Shaun Riome / Michael Ripley / Kevin Ripplinger / Christopher Rivest / Brian Rivoire / Dustin Rizzoli / Angelo Rizzuto / Greg Robbins / Reid Roberge / Joanne Roberts / Shirley Roberts / Suzanne Roberts / Jared Robertson / Neil Robertson
/ Marlin Robins / David Robinson / Heather Robinson / Matthew Robinson / Simon Robinson / Tony Robinson / Travis Robinson / William Robinson / Brian Roche / Pamela Rocuant / Craig Rodine / Alan Roessel / Doug Rogoschewsky / Melanie Rogoski / Bradley Rolfe / Stephanie Rolseth / Kathryn
Roman / Peggy Ronald / Patricia Rose / Brian Rosin / Dave Rossiter / Leor Rotchild / Shaun Roth / Shaun Roth / Lisa Rothwell / David Rough / Robert Rovers / Jeffrey Rowbottom / Kathy Ruhe / Arron Rush / Jeremy Rushton / Bruce Russell / Lynette Russell / Ivor Ruste / Daniela Ruzdijic / Duane
Ryan / Brandon St Jean / Jessica Sabourin / Noushin Sadeghpour / Andrew Sadler / Gregory Sadler / Ronnie Sadorra / Marvin Sagert / Aldrich Salazar / Raheleh Salehi Mojarad / Lindsay Salt / Sari Salt / Robert Salyn / farida Samji / Sharon Sampson / Ryan Samuel / Geoffrey Sander / Maureen Sander
/ Wayne Sandmaier / Sigfrid Santiago / Brian Sartison / Chris Saunders / Patrick Sauve / Karen Savinkoff / Matthew Savoia / Marcel Savoie / Craig Sawchuk / Coral Sawkins / Brian Sayer / Andrea Scaffo-Migliaro / Luciano Scarpino / Brandee Scarrott / Susan Schaar / Kimberly Schacher / Harry
Schaepsmeyer / Matthew Schamber / Ricky Scharf / Gary Scheifele / Evan Scheuerman / William Scheuerman / Dan Schiller / Randolph Schiller / Lana Schlosser / Erin Schmaltz / Rodney Schmidek / Brian Schmidt / Joel Schmitz / James Schmunk / Christopher Schneider / Lindsey Schneider / Mark
Schneider / Robert Schneider / Wesley Schneider / William Schneider / Gerry Schnell / Brian Scholten / Darrell Schuetzle / Loris Schuetzle / Glen Schultz / Troy Schwab / Eleanor Scott / Erin Scott / Kaylee Scott / Stephen Scott / Shannon Secreti / James Sedger / Brent Seib / Henry Seifried /
Brad Seipp / Carl Seitz / Steven Sellers / Nikki Sereres / Matthew Serfas / Donald Serink / James Setla / Rami Shabaneh / Travis Shackleton / Ali Sharif / Cary Shaw / Joni Shaw / Susan Shaw / Beverly Shea / Brenda Shepherd / Michael Shepherd / Amie Sherwin / Yi Shi / Corey Shideler / Karen
Shillingford / Ernest Sholtz / Andrew Sick / Mario Sicolo / Navjeet Sidhu / Kyle Silbernagel / Jane Simington / Rodney Simmons / Angela Simpson / Cindy Simpson / Ken Simpson / Lorelie Simpson / Malcolm Simpson / Shelly Simpson / Connie Sin / Greg Sinclair / Mathew Sinclair / Melanie Sinclair
/ Travis Singer / Gurpreet Singh / Usha Singh / James Sinnaeve / Song Sit / Zyg Siwy / Vladimir Sizov / Justin Sjogren / Martin Skaalrud / Karen Skrocki / Terrance Skrypnek / Jared Slater / Joel Slobogian / Derek Smale / Brad Small / Steven Small / Scott Smart / Stuart Smiley / Ryan Smilski / Amanda
Smith / Everett Smith / Jennifer Smith / Jeramie Smith / Karen Smith / Kerry Smith / Kristin Smith / Lindsay Smith / Maxwell Smith / Mervin Smith / Ronald Smith / Sarah Smith / Stephen Smith / Dennis Sneider / Cameron Snyder / Gregory Sobchyshyn / Kristi Soderman / Kristin Soffer / William
Soini / Jamie Solland / Kerrie Somerville / Michael Somerville / Arun Sood / Bradley Sorenson / Elias Soto / Janet Soucy / Michael Sparkes / Dwayne Spelay / David Speltz / Jordan Spencer / Janie Spenst / Jacqueline Sperle / Stanley Spiers / Dan Spitzer / Laurel Spivak / Elizabeth Springer / Rudy
Sprunger / Richard Squires / Jason St Amant / Paul St Amant / Kelly St. Germain / Darwin Stainbrook / William Stait / Travis Stambaugh / Gary Stangl / Shawn Stangness / Mark Stappler / Katherine Stavropoulos / Lisa Stebbins / Robert Steele / John Steeves / Kathleen Steiert / Lisa Stein / Craig
Stenhouse / Wayne Stenhouse / Trevor Stensby / Kristjan Stephansson / Blake Stevens / Brian Stevens / Jeffery Stevens / Sandra Stevens / Nicole Stewart / Raegan Stewart / Sydnee-Leigh Stewart / James Stirling / Shawn Stobbart / Dean Stobo / Linda Stock / Darryll Stone / William Stoneman /
Jeremy Stork / Kevin Stoski / Andrew Straile / Darcy Strate / Gregory Stratychuk / Brenda Streight / Lionel Stuber / Joshua Studer / Krystle Suchan / Jennifer Suen / Vitali Sukhetsky / Arjan Sulejmani / Jeffery Sullivan / Justin Sullivan / Sarah Sullivan / Colette Summers / Susan Sun / Rudy Sundermann
/ Judy Sutton / Benjamin Svoboda / Colyn Swanson / Darren Swaren / Tara Sweet / Joseph Swiech / Elizabeth Swift / Ken Switala / Jason Switzer / Donald Swystun / Ryan Sych / Mark Sykes / Jared Sylvestre / Pierre Sylvestre / Michael Taillon / Carla Tait / Neil Talbot / David Tam / Jennifer Tamura
/ Vernny Tang / Cody Taranko / Evan Tardif / Debra Tario / John Tarnasky / Landon Tarnasky / Ross Tarrant / Cameron Taylor / Scott Taylor / Sheila Taylor / Gary Tebb / Shane Tebb / Brittany Tebbenham / Paul Teha / Robert Templeton / Darwin Terlson / Mitchell Thew / Sharon Thiara / Bradley
Thiessen / Tyler Thiessen / Wayne Thomas / Christopher Thompson / Cody Thompson / Joel Thompson / Linda Thompson / Marion Thompson / Ryan Thompson / Scott Thompson / Melanie Thomson / Evelyn Thorkelson / Brenda Thorne / Nishi Thusoo / Bryan Tiessen / Robbie Tinis /
James Todd / Matthew Toews / Scott Toews / Scott Toews / Steven Tofan / Jillian Tofer / Dubravka Tomic / Shannon Tompkins / Henry Tong / Alfredo Torres / Gabriel Toth / Donnie Tradewell / Jennifer Tran / Kim Tran / Lisa Trang / Nathaniel Tredger / Leslie Tremblay / Russell Tremblay / Richard
Trost / Sharon Trottier / Johanne Trudel / Colin True / Warren Trumpour / Hoa Tsukishima / Carla Tucker / Lana Tucker / Catherine Tully / Gurpartap Tumber / Jean Turcotte / Dean Turner / Julia Turner / Ryan Turtle / John Turuk / Chandip Twana / Alister Twarzynski / Kerri Twemlow / Barney
Twidale / Keith Urlacher / Luis Urzua / Gordon Uswak / Tamara Utsch / Teresa Utsunomiya / Mora Uyesugi / Stephen Uzelman / Petrica Vaitus / Paul Valcourt / Jason Van Buskirk / Shane Van Buskirk / Mark Van de Veen / Brent Van Ham / Jeffrey Van Ham / Charlotte Van Pelt / Kerry Van Son / Angela
Van Unen / Kimberly Van Unen / Cheryl VanBastelaar / Arthur Vander Hoek / Paul Vander Valk / Kelly Vandesype / Tony Vandeweyer / Justin VanMaarion / Tyson Vany / Theresa Varalta / Erika Vargas / Adam Varley / John Varsek / Greg Vatcher / Cody Vaughan / Haig Vejprava /
Bernadette Velasco / Lazar Velev / Darren Venne / Natasha Verdon / Jerrod Verhaest / Michael Vermeersch / Mike Verrier / Wilhelmina Versloot / Brian Verville / Jillian Viccars / Sheldon Vigoren / Leonidas Villegas / Ryan Vinck / Shaireen Virani / Phonesavanh Viravong / Lori Virtue / John Visser /
Raymond Von Niessen / Cindy Wachtler / Sean Wade / Lee Wagner / Steven Wagner / Heather Wagstaff / Vivian Wahby / Duane Walkeden / Twila Walkeden / Kirstin Walker / Rennick Walker / Taura Walker / Sheldon Wall / Steven Wall / Steve Wallace / Tarnia Wallace / Hayward Walls / Ryan
Walper / Andrew Walsh / Andrew Walsh / Tieshan Wang / Corwin Wanuch / Darcey Ward / Michelle Ward / Kathleen Ware / Allison Warkentin / Anthony Warren / Darryl Warren / Scott Waschuk / Kitty Wasslen / Michael Wasylyk / Michele Waters / Jayson Watier / Jeff Watier / Catherine Watson
/ Robert Watson / Robert Watson / Rick Watters / Katherine Wattie / Arlette Watwood / Richard Wawrykowych / Evan Way / Loy Webb / David Webber / Pamela Weber / Paul Weber / Colin Webster / Dale Webster / Pamela Webster / Rodney Webster / Richard Wegerhoff /
Heather Weighill / Betty Weightman / Ryan Weimer / Simon Weintz / Shawna Weir-Murphy / Lyle Weiss / Lyle Weiss / Neil Wenman / Michael Wenner / Sara Wentz / Gregory Wenzel / Trevor Weppler / Nigel Werenka / Margaret Werezak / Scott Werre / Barry Weseen / Dann Weselosky / Jeff
West / Patricia Westman / Trevor Westman / Bradley Wheeler / Deanne Wheeler-felstad / Colleen Whelehan / Charles Whitaker / Curtis White / Mergitte White / Vanessa White / William White / Lorna Whiteway / Albert Whitford / Jack Whittaker / Phoinyx Whittingham / Carol Whorms
/ Carol Whorms / Jeneane Whyte / Russell Wickes / Catherine Widdoes / Michael Wiebe / Trevor Wiebe / Linda Wiegand / Ralph Wieler / Brett Wiens / Lane Wieteska / Becky Wigemyr / Lori Wilhelm-Einsporn / Candise Wilkins / frederick Wilkinson / Jessica Wilkinson / Karen Will / Adam
Willcott / Cory Williams / Larry Williams / Tyler Williams / Darryl Williamson / John Williamson / Caroline Wilson Mussbacher / Carrie Wilson / Cedric Wilson / frances Wilson / Jeffrey Wilson / Micheal Wilson / Robert Wilson / Russell Wilson / Shauna Wilson / Cory Winder /
Henry Winnicki / Allan Winquist / Nathan Winter / Riley Winter / Gary Witiw / Dean Wolansky / Cindy Wolfe / Murray Wolfe / William Wolfe / John-Paul Wolff / Dale Woloshen / Benjamin Wong / Jim Wong / Lucia Wong / Deanna Woo / Kevin Woo / Blake Wood / Nicole Woodland / Mary
Woods / Troy Woods / Garfield Woodward / Caroline Worobo / Rachelle Woroniuk / Leonard Wourms / Darin Wright / Stan Wright / John Wrobel / Xinjie Wu / Kerry Wycislik / Brent Wyness / James Yaholnitsky / Daniel Yake / Robert Yanke / Robert Yanke / Jessica Yarnell / Kim Yee / Larry Yee
/ Tony Yee / Sung Youn / Darla Young / Elizabeth Young / Ian Young / Janet Young / John Young / Rodney Young / William Young / Alice Yu / Carolyn Yu / David Yu / Tze Yu / Luningning Yue / Nicole Yuen / Arthur Yukim / Trenton Zacharias / James Zakariasen / Maliha Zaman / Roger Zavagnin /
Mohamud Zaver / Sandra Zdunich / Khalil Zeidani / Remo Zelantini / Jason Zelinski / Amy Zhang / Weimin Zhang / Yi Zhang / Ian Ziebart / Russ Ziegler / Drew Zieglgansberger / Oral Zihove / Melissa Zimmerman / James Zinger / Ronald Zittel / Lynette Zyznomirski
CENOVUS 201 0 A NNUA L REPO RT · M EE T OUR EM P LOY E ES · 3 0
AS AT DECEMBER 31, 2010
MeeT ouR BoaRD oF DiReCT
oRs
The members of the Cenovus Board of Directors have
years of experience. Their breadth of skills guides our
decisions and actions.
DIVERSE EXPERTISE + QUALITY DISCUSSION = insightFul guidance
(Pictured left to right)
ChaRLes M. RaMpa Ce k
paTRiCk D. DanieL
R aLph s . Cun ni nghaM
ian W. DeL aneY
MiChaeL a . g RanDi n (Board Chair )
VaLeRie a . a . nieLse n
BRi an C . FeR guso n
WaYne g. ThoMso n
CoLin Ta YLoR
31 · MEET OUR BOARD Of DIRECTORS · CENOVUS 2010 A NNUAL REPORT
M essage FR oM ouR BoaRD ChaiR
“Your Executive Team and your Board are off to a strong
start in realizing the great potential that is Cenovus.”
GOOD GOVERNANCE + STRATEGIC DECISIONS = a company to Believe in
“After reading this annual report,
I think you will agree that Cenovus’s
first year performance couldn’t have
been much better.”
from a governance perspective, we believe
that the Board got off to a great start as well.
The management proxy circular describes,
in some detail, your Directors’ qualifications
and your Board’s actions with respect to
regulatory compliance, self-regulation, executive
compensation and other important Board
and Committee matters. However, I thought
a few comments here might give you a better
understanding of how your Board is operating.
We have a nine-member Board with a good
mix of skills. The smaller size is intended to
encourage open and inclusive discussion. The mix
of skills captures experience in both upstream
and downstream oil and gas operations and
transportation, as well as in accounting, finance
and general business and board operations. This
combination leads to good quality debate and
questioning based on knowledge of the business,
all with a view to helping the Executive Team
make high-quality decisions.
During the year, we focused much of our
attention on strategy and risk management. We
worked with the Executive Team to ensure that
Cenovus’s initial strategy built on the rationale for
the company’s creation and took full advantage
of its physical asset base, the technical expertise
of its people and its financial capacity. At the
same time, and also with the Executive Team,
we made sure all the risks that we could foresee
were included in Cenovus’s well-developed risk
monitoring and mitigation system.
for reasons such as these we believe your
company, your Executive Team and your Board
are off to a strong start in realizing the great
potential that is Cenovus.
Respectfully submitted on behalf of the Board.
MICHAEL A . GRA N DIN
BOARD CHAI R
WhaT a gRe a T s TaRT FoR Ce n o Vus!
Cenovus began with an excellent portfolio of
assets. It has vast and largely undeveloped oil
sands resources to provide for growth well into the
future. It has established oil and natural gas assets
to fund this growth. It has the technical know-
how to effectively recover its resources and the
project management expertise to do so efficiently.
Perhaps most importantly, it has a highly engaged
and enthusiastic workforce, motivated by attractive
opportunities, whose members are eager to
convert potential value into present value.
After reading this annual report, I think you will
agree that Cenovus’s first year performance
couldn’t have been much better.
CENOVUS 201 0 A NNUA L REPO RT · M ESS AGE fRO M OUR BOA RD C H AIR · 32
opeRa Ting anD FinanCi aL highLighT
s
o p eR aT i n g h i g h L i g h T s
B E f O R E R OYA LT I E S
production
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands – Heavy Oil
foster Creek
Christina Lake
Total
Pelican Lake
Senlac
Conventional Liquids
Heavy Oil
Light and Medium Oil
Natural Gas Liquids
Total Crude Oil and Natural Gas Liquids (bbls/d)
Natural Gas (MMcf/d)
Refinery operations(1)
Crude Oil Capacity (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Crude Utilization (%)
proved reserves(2) (3)
Total Reserves (MMBOE)
Year-end Bitumen Reserves (MMbbls)
Total Production Replacement (%)
Recycle Ratio(4)
Proved finding & Development Costs ($/BOE)(5)
Reserve Life Index (years)
2010
2009
% change
51,147
7,898
59,045
22,966
–
82,011
16,659
29,346
1,171
129,187
737
452
386
86
1,666
1,154
398
7.8
3.65
18
37,725
6,698
44,423
24,870
3,057
72,350
17,888
30,394
1,206
121,838
837
452
394
87
1,398
866
205
5.1
5.39
15
36
18
33
(8)
–
13
(7)
(3)
(3)
6
(12)
–
(2)
(1)
19
33
94
53
(32)
20
(1) Represents 100% of the Wood River and Borger refinery operations.
(2) Natural gas is converted using a 6:1 oil equivalent. See the Advisory section of the MD&A.
(3) 2009 estimates prepared in accordance with U.S. disclosure requirements using constant prices and costs. 2010 estimates prepared in accordance with Canadian disclosure requirements using forecast
prices and costs. See the Oil and Gas Reserves and Resources section of the MD&A for more information.
(4) for additional information regarding our Recycle Ratio, see our 2011 Management Proxy Circular, available at www.cenovus.com.
(5) finding and Development Costs presented do not include changes in future development costs. for a description of the calculations used, refer to our Additional Advisory on page 132. finding and
Development Costs calculated with changes in future development costs, for proved reserves and for proved plus probable reserves, are disclosed in the Additional Advisory on page 132.
F i n a n C i aL h i g h Li g h T s
$ M I L L I O N S , E XC E P T P E R S H A R E A N D OT H E R A M O U N T S A S N OT E D
2010
2009
% change
Gross Revenues
Net Revenues
Cash flow (1)
Per Share – Diluted
Net Earnings
Per Share – Diluted
Operating Earnings (1)
Per Share – Diluted
Capital Investment
Net Acquisition and Divestiture Activity
Net Capital Investment
Dividends Per Common Share ($/share)(2)
Dividend Yield (%) (3)
Debt to Capitalization (%)(1)
Debt to Adjusted EBITDA (times) (1)
14
13
(15)
21
(48)
(2)
(2)
13,422
12,973
2,415
3.21
993
1.32
794
1.06
2,122
(221)
1,901
11,790
11,517
2,845
3.79
818
1.09
1,522
2.03
2,162
(219)
1,943
c$0.80
2.40
US$0.20
3.17
26
1.2
28
1.1
(1) Non-GAAP measures as referenced in the Advisory section of the MD&A.
(2) fourth quarter dividend paid in December 2009 reflects an amount determined in connection with the Arrangement (defined on page 36) based on carve-out earnings and cash flows.
(3) 2010 based on TSX closing share price at year end. 2009 based on NYSE closing share price at year end and using annualized dividend.
33 · OPERATING AND fINANCIAL HIGHLIGHTS · CENOVUS 201 0 ANNUAL REPORT
m anagement ’s discussi on and ana lys i s
Introduction and Overview of Cenovus Energy ...........................................................................................................................................................................................................................35
Overview of 2010 ......................................................................................................................................................................................................................................................................................... 37
Financial Information ................................................................................................................................................................................................................................................................................. 41
results of Operations ................................................................................................................................................................................................................................................................................47
Operating Segments .................................................................................................................................................................................................................................................................................. 49
Upstream ................................................................................................................................................................................................................................................................................................... 49
Oil sands .............................................................................................................................................................................................................................................................................................. 49
Conventional ......................................................................................................................................................................................................................................................................................52
refining and Marketing ........................................................................................................................................................................................................................................................................56
Corporate and Eliminations ....................................................................................................................................................................................................................................................................58
Quarterly Financial Data ..........................................................................................................................................................................................................................................................................60
Oil and Gas reserves and resources .................................................................................................................................................................................................................................................. 61
liquidity and Capital resources .......................................................................................................................................................................................................................................................... 64
risk Management .........................................................................................................................................................................................................................................................................................67
accounting policies and Estimates .......................................................................................................................................................................................................................................................71
Outlook ............................................................................................................................................................................................................................................................................................................75
advisory ............................................................................................................................................................................................................................................................................................................76
abbreviations ...........................................................................................................................................................................................................................................................................................77
For the Year Ended December 31, 2010
(Canadian Dollars)
this Management’s Discussion and analysis (“MD&a”) for Cenovus Energy Inc., dated
February 18, 2011, should be read with our audited Consolidated Financial Statements
for the year ended December 31, 2010 (“Consolidated Financial Statements”). this
MD&a contains forward-looking information about our current expectations, estimates
and projections. For information on the risk factors that could cause actual results to
differ materially and the assumptions underlying our forward-looking information, as
well as definitions used in this document, see the advisory at the end of this MD&a.
Management is responsible for preparing the MD&a, while the audit Committee of
the Cenovus Board of Directors (the “Board”) reviews the MD&a and recommends its
approval by the Board.
this MD&a and the Consolidated Financial Statements and comparative information
have been prepared in Canadian dollars, except where another currency is indicated,
and in accordance with Canadian Generally accepted accounting principles (“Gaap”).
production and reserve volumes are presented on a before royalties basis. Certain
amounts in prior years have been reclassified to conform to the current
year’s presentation.
CENOVUS 201 0 aNNUal rEpOrt · MaNa GEM E Nt ’S DISCUSSION aND aNal YSIS · 34
Introduction and Overview of Cenovus Energy
Cenovus is a Canadian oil company headquartered in Calgary, Alberta, with
a market capitalization of approximately $25 billion on December 31, 2010.
In 2010, we had total crude oil, natural gas and NGL production in excess of
250,000 barrels of oil equivalent per day.
Our operations include oil sands projects in northern Alberta, including
Foster Creek and Christina Lake. These two properties are located in the
Athabasca region and use steam-assisted gravity drainage (“SAGD”) to extract
crude oil. Also located within the Athabasca region is our pelican Lake
property, where we have an enhanced oil recovery project using polymer
flood technology, as well as our emerging Grand rapids project. In southern
Saskatchewan, we inject carbon dioxide to enhance oil recovery at our
Weyburn operation. We also have established conventional crude oil and
natural gas production in Alberta and Saskatchewan. In addition to our
upstream assets, we have 50 percent ownership in two refineries in Illinois
and Texas, U.S.A., enabling us to partially integrate our operations from crude
oil production through to refined products such as gasoline, diesel and jet
fuel to reduce volatility associated with commodity price movements.
Our operational focus over the next five years will be to increase production,
predominantly from Foster Creek and Christina Lake as well as pelican
Lake and to continue assessment of our emerging resource base. We have
proven our expertise and low cost oil sands development approach and
our conventional crude oil and natural gas production base is expected
to generate reliable production and cash flows which will enable further
development of our oil sands assets. In all of our operations, whether crude
oil or natural gas, technology plays a key role in improving the way we extract
the resources, increasing the amount recovered and reducing costs. Cenovus
has a knowledgeable, experienced team committed to continuous innovation.
One of our most significant ongoing objectives is to advance technologies
that reduce the amount of water, steam, natural gas and electricity consumed
in our operations and to minimize surface land disturbance.
Our future lies in developing the land position that we hold in the Athabasca
region in northeast Alberta. In addition to our Foster Creek and Christina Lake
oil sands projects, we currently have three emerging projects in this area:
Narrows Lake (1)
Grand rapids
Telephone Lake
(1) Approximate ownership interest
Ownership Interest
50 percent
100 percent
100 percent
At our Narrows Lake property, located within the Christina Lake region, we
have submitted a joint application and environmental impact assessment
(“EIA”). This project is expected to begin producing in 2016, and is expected
to have a gross production capacity of 130,000 bbls/d. At our Grand rapids
property, which is located within the Greater pelican region, a pilot project
is underway. If this pilot is determined to be successful, we expect to file
a regulatory application for a commercial operation with gross production
capacity of 180,000 bbls/d. Our Telephone Lake property is located within
the Borealis region. We have submitted a regulatory application for the
development of this property, including the construction of a facility with
gross production capacity of 35,000 bbls/d.
We have a number of opportunities to deliver shareholder value,
predominantly through production growth from our resource position in
the oil sands, most of which is undeveloped. Our 10 year business plan is
to grow our net oil sands production from approximately 60,000 bbls/d
in 2010 to 300,000 bbls/d by the end of 2019. Growth is expected to be
primarily internally funded through cash flow generated from our established
crude oil and natural gas production base where we also have opportunities
to add production through new technologies. Our natural gas production
provides an economic hedge for the natural gas required as a fuel source
at both our upstream and refining operations. Our refineries, which are
operated by Conocophillips, an unrelated U.S. public company, enable us to
moderate commodity price cycles by processing heavy oil, thus economically
integrating our oil sands production. A key milestone in this regard is the
planned 2011 coker startup of the Coker and refinery Expansion (“COrE”)
project at the Wood river refinery. We also employ commodity hedging to
enhance cash flow certainty. In addition to our strategy of growing net asset
value, we expect to continue to pay meaningful dividends to deliver strong
total shareholder return over the long term.
35 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Our BusInEss struCturE
Our operating and reportable segments are as follows:
2009 FinanCial inFORMatiOn
Cenovus began independent operations on December 1, 2009, as a result
of the plan of arrangement (“Arrangement”) involving Encana Corporation
(“Encana”) whereby Encana was split into two independent energy companies,
one a natural gas company, Encana and the other an oil company, Cenovus.
The results for the year ended December 31, 2010 and the one month period
from December 1 to December 31, 2009 represent the Company’s operations,
cash flow, and financial position as a stand-alone entity. The results for the
periods prior to the Arrangement, being January 1 to November 30, 2009
and January 1 to December 31, 2008 have been prepared on a “carve-out”
accounting basis whereby results have been derived from the accounting
records of Encana using the historical results of operations and historical
basis of assets and liabilities of the businesses transferred to Cenovus. Further
information on the carve-out assumptions can be found in the notes to the
Consolidated Financial Statements.
• Upstream, which includes Cenovus’s development and production
of crude oil, natural gas and NGLs in Canada, is organized into two
reportable operations:
– Oil Sands, which consists of Cenovus’s producing bitumen assets at
Foster Creek and Christina Lake, heavy oil assets at pelican Lake, new
resource play assets such as Narrows Lake, Grand rapids and Telephone
Lake, and the Athabasca natural gas assets. Certain of the Company’s oil
sands properties, notably Foster Creek, Christina Lake and Narrows Lake,
are jointly owned with Conocophillips and operated by Cenovus.
– Conventional, which includes the development and production of
conventional crude oil, natural gas and NGLs in western Canada.
• Refining and Marketing, which is focused on the refining of crude
oil products into petroleum and chemical products at two refineries
located in the U.S. The refineries are jointly owned with and operated by
Conocophillips. This segment also markets Cenovus’s crude oil and natural
gas, as well as third-party purchases and sales of product that provide
operational flexibility for transportation commitments, product type,
delivery points and customer diversification.
• Corporate and Eliminations, which primarily includes unrealized gains
or losses recorded on derivative financial instruments as well as other
Cenovus-wide costs for general and administrative and financing activities.
As financial instruments are settled, the realized gains and losses are
recorded in the operating segment to which the derivative instrument
relates. Eliminations relate to sales and operating revenues and purchased
product between segments recorded at transfer prices based on current
market prices and to unrealized intersegment profits in inventory.
The operating and reportable segments shown above were changed from
those presented in prior periods to better align with our long range business
plan. All prior periods have been restated to reflect this presentation.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 36
Overview of 2010
2010 marked our first full year operating as an independent company, and we delivered very strong performance overall.
Excellent operating performance reflected strong oil sands production
growth, with very good operating and capital cost controls to maintain our
position as a low cost producer. Despite diminished realized natural gas
prices, which resulted from the large oversupply of natural gas markets and
crude oil pipeline disruptions, both of which impacted our operating cash
flows, we achieved our 2010 cash flow guidance and generated net earnings
of $993 million which exceeded 2009 by 21 percent. In addition, managing our
business with a continual focus on value creation, cost control and updated
credit facilities resulted in Cenovus having an even stronger financial position
at the end of 2010 than at the start of the year.
Specific highlights for 2010 include:
• Operating cash flow from refining and Marketing decreasing by
$293 million mainly due to planned turnarounds at both refineries, higher
average crude costs and refinery optimization activities due primarily to
weaker diesel and gasoline prices primarily in the first half of 2010.
partially offsetting these decreases were lower operating expenses and
a strengthening of the Canadian dollar;
• Net earnings increasing $175 million mainly due to unrealized foreign
exchange gains, unrealized mark-to-market hedging gains and lower income
taxes, partially offset by lower operating cash flows;
• Our debt metrics improving with debt to capitalization decreasing to
26 percent and debt to adjusted EBITDA being 1.2x; and
• Substantial growth in our bitumen proved reserves (year-over-year increase
• Declaring and paying dividends of $601 million ($0.20 per share per
of 288 MMbbls), resulting in very low finding and development costs;
• production from our Foster Creek and Christina Lake oil sands projects
quarter) in 2010 compared to US$150 million in 2009 paid in connection
with the Arrangement.
increasing by 33 percent;
reserves and resources
• receiving regulatory approval for Foster Creek expansion phases F, G and H;
• Capital spending on the Foster Creek and Christina Lake expansions
increasing significantly, consistent with our strategy to move these projects
forward; and
• Our Conventional crude oil and natural gas business generating more than
$1.2 billion in operating cash flow in excess of the related capital spent to
fund the development of our oil sands projects.
Additional operating and financial highlights for 2010 compared to
2009 include:
• Total capital spending being relatively unchanged year over year, however,
spending on our oil sands projects increased 38 percent to $867 million
while spending on our refineries decreased 37 percent to $655 million. In
our Conventional upstream business, our spending focus on oil increased
to 68 percent of spending ($358 million) in 2010 compared to 48 percent
($223 million) in 2009;
• proceeds from the divestiture of property, plant and equipment totaled
$307 million (2009 - $222 million);
• Net revenues increasing 13 percent mainly due to improved crude oil and
refined product prices despite pipeline transportation disruptions of crude
oil from Alberta to mid-west U.S. refineries in the second half of 2010
and higher royalties as a result of Foster Creek achieving payout status for
royalty purposes;
• As expected, based on realized natural gas prices declining 34 percent
and natural gas volumes declining 12 percent (including the impact of
divestitures) we had a decrease in our Upstream operating cash flow
of $921 million. The lower natural gas prices and lower operating cash flow
from refining and Marketing resulted in decreases to our cash flow of
$430 million and operating earnings of $728 million. The natural gas decreases
were partially offset by higher crude oil volumes and realized prices;
The receipt of Alberta Energy resources Conservation Board (“ErCB”)
regulatory approval for expansion phases F, G and H at Foster Creek, including
expansion of the development area, combined with an overall increased
recovery factor in the area, has resulted in a significant increase to our
proved bitumen reserves in 2010. In 2010, we also issued two news releases
highlighting detailed information related to our bitumen initially-in-place,
contingent resources and prospective resources, which enable investors to
more fully understand our inventory of oil sands assets.
We also provided further information about our resources and development
plans at our Investor Day presentations in June 2010 and at the end of
2010 the estimates of bitumen contingent and prospective resources were
updated. Our best estimate bitumen contingent resources at December 31,
2010 were approximately 6.1 billion barrels and our best estimate bitumen
prospective resources were approximately 12.3 billion barrels.
Foster Creek
Our Foster Creek property achieved project payout for royalty purposes
in February 2010. project payout is achieved when the cumulative project
revenue exceeds the cumulative project allowable costs. As a result, Foster
Creek’s royalties increased from $19 million and an effective royalty rate
of 2.7 percent in 2009 to $165 million and an effective royalty rate of
16.2 percent in 2010, which includes pre-payout royalties for one month.
As noted above, we received regulatory approval from the ErCB for the next
three expansion phases at Foster Creek, F, G and H. When all three phases are
complete, Foster Creek’s gross production capacity is expected to increase
from the current 120,000 bbls/d to 210,000 bbls/d. The next step for these
expansions is to receive final partner approval, which is expected in 2011.
Engineering and preliminary ground work on phase F is already underway.
First production for phase F is expected to be accelerated by 12 months to
2014 compared to our original plan. production from the other two phases
is expected in 2016-2017.
37 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Christina Lake
Net Capital Investment
The construction of the Christina Lake expansion is progressing with phases C
and D each expected to add an additional 40,000 bbls/d of gross production
capacity. Start up of phase C is expected to begin with steam injection in the
second quarter of 2011 and production commencing in the second half of
2011. production from phase D has been advanced from its original planned
start by approximately six months and is now targeted to begin in 2013. These
expansion phases are expected to bring Christina Lake’s gross production
capacity to 98,000 bbls/d in 2013.
New resource plays
We have announced our intention to move ahead with the development
of Narrows Lake, which may use a combination of SAGD and Solvent Aided
process (“SAp”) to recover the bitumen. SAp is a technological improvement
applied to our SAGD operations that helps maximize the amount of bitumen
recovered and requires less steam and water usage. SAp takes the benefit
of injecting steam in the SAGD process and combines it with solvents, such
as butane, to help bring the bitumen to the surface. In the first quarter of
2010, we initiated the regulatory approval process by filing proposed terms
of reference for an EIA and began public consultation for the project. In
the second quarter of 2010, final terms of reference were issued by Alberta
Environment and a joint application and EIA was filed.
In 2010, we received approval from the ErCB and Alberta Environment to
begin a pilot project at our Grand rapids project. The drilling of a SAGD well
pair and construction of associated facilities is complete and steam injection
commenced in December 2010.
As part of our efforts to progress these emerging projects, in 2010, we
significantly increased our spending to $124 million in new resource play areas
including the drilling of over 150 gross stratigraphic wells and commencing
our Grand rapids pilot project. In addition, we continued our research
and development efforts that we expect will continue to reduce our land
footprint, water use and air emissions intensity.
refining COrE project
At the end of 2010, the COrE project progressed to approximately 91 percent
complete from 71 percent at the beginning of the year. Commissioning of
several of the process units has been completed with an expected coker start
up in the fourth quarter of 2011. At the time of coker start up, we expect that
COrE expenditures will reach approximately US$3.7 billion (US$1.85 billion
net to Cenovus). The total estimated cost of the COrE project is expected to
be approximately US$3.9 billion (US$1.95 billion net to Cenovus), or about 10
percent higher than originally forecast.
Unusual weather patterns across our operating areas throughout the year,
including a very wet summer, restricted access to our properties and with
continued low commodity prices we chose to reduce spending, which
has resulted in our upstream capital investment program being lower than
originally planned in some of our operating areas. Although upstream
capital spending is lower than expected, production levels have remained at
expected levels. Our refining capital spending was also lower than expected
as unusually high water levels on the Mississippi river delayed deliveries of
various COrE modules, deferring some 2010 spending to 2011. As part of our
ongoing portfolio management strategy, we divested of certain non-core oil
and gas assets for proceeds of $221 million, which reduced our 2010 crude oil
and NGLs production by approximately 975 bbls/d (one percent) and natural
gas production by approximately 33 MMcf/d (four percent). In total, our 2010
property, plant and equipment divestitures resulted in proceeds of $307 million.
Net revenues
During the second half of 2010, pipeline disruptions and apportionment
challenges restricted the access of Alberta crude oil to U.S. markets. As a
result, there were higher inventory levels of WCS and a widening of the WTI-
WCS price differential in the second half of 2010. The widened WTI-WCS
differential had a negative impact on our upstream revenue; however our
refining operations benefitted somewhat due to a lower cost for purchased
product. While the effects of pipeline apportionment did not significantly
affect our production, it did result in lower sales volumes in the second half
of 2010 as we added volumes to storage at the end of 2010.
With respect to commodity prices, our strategy is to use financial instruments
to protect and provide certainty on a portion of our cash flows and therefore
commodity price hedging activity continues to be an important element of
our business model. This activity reflects our objective of locking in prices on
a portion of our natural gas and crude oil production such that we protect
a significant portion of the subsequent years’ cash flows. realized after-tax
hedging gains of $199 million during 2010 (2009–gains of $804 million) reflect
the benefits of locking in commodity prices in excess of the current period
benchmark prices. These realized hedging gains are significantly less than
those of 2009 since they effectively reflect the significant over supply and
deterioration of natural gas markets and prices over the last two years. Our
hedging strategy continues to be sound and allowed us to put in place natural
gas hedges for 2010 at approximately $6.00 per Mcf as compared to hedges
for 2009 put in place at approximately $9.00 per Mcf when future prices were
higher in 2008. For more information on our realized hedging prices, refer to
the Operating Netbacks in the results of Operations section of this MD&A.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 38
O u r B u s I n E s s E n v I r O n m E n t
Key performance drivers for our financial results include commodity prices,
price differentials, refining crack spreads as well as the U.S./Canadian dollar
exchange rate. The following table shows select market benchmark prices and
foreign exchange rates to assist in understanding our financial results.
S E l E C t E d B E n C h M a R k P R i C E S ( 1 )
2010
Q4
Q3
Q2
Q1
2009
Q4
Q3
Q2
Q1
2008
Crude Oil Prices (US$/bbl)
West Texas Intermediate
Average
End of period spot price
Western Canada Select
Average
End of period spot price
Average price –
Differential WTI-WCS
Condensate
(C5 @ Edmonton)
Average price – Differential
WTI-Condensate
(premium)/discount
refining margin 3-2-1 Crack spread(2) (US$/bbl)
Chicago
Midwest Combined (Group 3)
natural Gas Prices
AECO ($/GJ)
NYMEX (US$/MMBtu)
Basis Differential NYMEX-AECO (US$/MMBtu)
Foreign Exchange
79.61 85.24
76.21 78.05 78.88
62.09
76.13 68.24
59.79
43.31
91.38 91.38 79.97 75.63 83.45
79.36
79.36
70.46
69.82
49.64
65.38
67.12 60.56 63.96 69.84
52.43
64.01
58.06
52.37
34.38
72.87 72.87 64.97 61.38 70.25
71.84
71.84
59.76
59.12
42.69
99.75
44.60
79.70
35.40
14.23
18.12
15.65
14.09
9.04
9.66
12.12
10.18
7.42
8.93
20.05
81.91 85.24
74.53 82.87 84.98
61.35
74.42
65.76
58.07
46.26
106.22
(2.30)
–
1.68
(4.82)
(6.10)
0.74
1.71
2.48
1.72
(2.95)
(6.47)
9.33
9.48
9.25
10.34
11.60
6.11
9.12
10.60
11.38
6.82
8.54
8.09
5.00
8.48
10.95
5.52
8.06
9.16
9.75
9.62
3.91
3.39
4.39
3.80
0.40
0.28
3.52
4.38
0.78
3.66
5.08
4.09
0.32
5.30
0.19
3.92
3.99
0.40
4.01
4.17
0.19
2.87
3.39
0.67
3.47
3.50
0.39
5.34
4.89
0.35
11.22
11.03
7.71
9.04
1.23
Average US/Canadian dollar exchange rate
0.971 0.987 0.962 0.973 0.961
0.876 0.947
0.911 0.857 0.803
0.938
(1) These benchmark prices do not include the impacts of our hedging program or reflect our sales prices. For our realized sales prices, refer to the Operating Netbacks in the results of Operations section
of this MD&A.
(2) 3-2-1 Crack Spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of ultra low sulphur diesel.
39 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
The global economic recovery that began in the second half of 2009
continued throughout 2010 resulting in increased crude oil demand, mainly
from China, other Asian countries and the United States, and was reflected
in higher WTI benchmark prices. The closing price of WTI at the end of 2010
increased 15 percent from the 2009 closing price and was more than double
the 2008 closing price. While crude oil demand increased compared to 2009
and global production levels from both OpEC and non-OpEC countries has
increased, significant spare OpEC production capacity still remained at the
end of 2010. Further increases in OpEC production could result in a lowering
of crude oil prices. WTI is an important benchmark as it is also used as the
basis for determining royalties for a number of our crude oil properties.
WCS is a blended heavy oil which consists of both conventional heavy oil
and unconventional diluted bitumen. This blended heavy oil is usually traded
at a discount to the light oil benchmark, WTI. The widening of the WTI-
WCS differential in 2010 was partially the result of pipeline transportation
disruptions of crude oil from Alberta to mid-west U.S. refineries as well as
refinery downtime in certain regions of the U.S. in the second half of 2010.
While overall the price of WCS increased in 2010 compared to 2009, pipeline
disruptions resulted in increased WCS inventory which negatively impacted
its market price. At the same time, the price of WTI increased substantially
in 2010 resulting in the differential widening to as much as US$31.00 per
bbl during the year. The end of 2010 saw the differential narrowing to
approximately US$18.51 per bbl.
Blending condensate with bitumen enables our bitumen and heavy oil
production to be transported. The WTI-condensate differential is the
benchmark price of condensate relative to the price of WTI. As purchased
condensate is sold as part of the crude oil blend, the cost of condensate
purchases impacts both our revenues and transportation and blending costs.
The differentials for WTI-WCS and WTI-Condensate are independent of one
another and tend not to move in tandem.
Benchmark refining margin crack spreads for 2010 improved from 2009 due,
in part, to an increase in consumer demand for refined products partly due
to the improved economy in the U.S., resulting in increased gasoline and
distillate consumption. However, most of the improvement can be attributed
to weaker WTI prices relative to other global crude and product prices as a
result of pipeline congestion in inland U.S. markets.
In 2010, benchmark NYMEX natural gas prices showed marginal improvement
primarily due to increased consumption for electric power generation due to
record summer heat as well as natural gas prices becoming more economical
than certain coal as a fuel source for power generation. 2010 also saw natural
gas demand increase for use in the industrial sector of the U.S. While NYMEX
natural gas prices were higher in 2010 compared to 2009, throughout 2010
the NYMEX price has been generally on a downward trend. The main cause
of the declining natural gas prices in 2010 was natural gas supply. Industry
wide natural gas drilling activity, primarily from shale gas, remained strong
in 2010 which resulted in higher levels of North American natural gas
production as well as volumes in storage increasing to record high levels
despite declining market prices.
During 2010, the Canadian dollar strengthened relative to the U.S. dollar,
primarily since the economic recovery in Canada moved at a greater pace
than in the U.S. An increase in the value of the Canadian dollar compared
to the U.S. dollar has a negative impact on our revenues as the sale prices
of our crude oil and refined products are determined by reference to U.S.
benchmarks. Similarly, our refining results are in U.S. dollars and therefore a
strengthened Canadian dollar reduces this segment’s reported results.
Our risk mitigation strategy has helped reduce our exposure to commodity
price volatility. realized hedging gains, after-tax, in 2010 were $199 million
(2009–gains of $804 million; 2008–losses of $196 million). Further information
regarding our hedging program can be found in the notes to the Consolidated
Financial Statements.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 40
Financial Information
In our financial reporting to shareholders for the year ended December 31,
2009, we used U.S. dollars as our reporting currency and reported production
on an after royalties basis. Effective January 1, 2010, we changed our reporting
currency to Canadian dollars and our reporting of production to a before
royalties basis. This change in reporting currency and protocol was made to
better reflect our business, and allows for increased comparability to our
peers. With the change in reporting currency and protocol, all comparative
information has been restated from U.S. dollars to Canadian dollars and
production from after royalties to before royalties.
s E L E C t E D C O n s O L I DAt E D F I n A n C I A L r E s u Lt s
( $ m i lli o n s , e x c e p t p e r s h a r e a m o u n t s)
Net revenues
Operating Cash Flow (1)
Cash Flow (1)
- per share – diluted (2)
Operating Earnings (1)
- per share – diluted (2)
Net Earnings
- per share – basic (2)
- per share – diluted (2)
Total Assets
Total Long-Term Debt
Other Long-Term Obligations
Capital Investment
Free Cash Flow (1)
Cash Dividends (3)
- per share (3)
(1) Non-GAAp measure defined within this MD&A.
2010
12,973
2,975
2,415
3.21
794
1.06
993
1.32
1.32
22,095
3,432
6,156
2,122
293
601
0.80
2010 vs
2009
13%
-29%
-15%
-48%
21%
2%
-6%
-5%
-2%
-57%
2009
11,517
4,189
2,845
3.79
1,522
2.03
818
1.09
1.09
21,755
3,656
6,507
2,162
683
159
US$0.20
2009 vs
2008
-34%
7%
-9%
-6%
-68%
-4%
-2%
-11%
-2%
-25%
2008
17,570
3,933
3,115
4.14
1,620
2.15
2,526
3.37
3.36
22,614
3,719
7,308
2,204
911
n/a
n/a
(2) Any per share amounts prior to December 1, 2009 have been calculated using Encana’s common share balances based on the terms of the Arrangement, wherein Encana shareholders received one common
share of Cenovus and one common share of the new Encana.
(3) The 2009 dividend reflected an amount determined in connection with the Arrangement based on carve-out earnings and cash flow.
41 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
n E t r E v E n u E s v A r I A n C E
( $ m i lli o n s)
Net revenues for the Year Ended December 31, 2009
$
11,517
Increase (decrease) due to:
Upstream
prices
realized hedging
Volume
royalties
Condensate and Other (1)
refining and Marketing
Corporate and Eliminations
Unrealized hedging
Other
net revenues for the Year Ended December 31, 2010
$
238
(882)
(43)
(176)
299
$
728
(14)
(564)
1,306
714
$
12,973
(1) revenue dollars reported include the value of condensate sold as bitumen or heavy oil blend. Condensate costs are recorded in transportation and blending expense.
The increase in net revenues for 2010 is comprised of two main items.
Our Upstream net revenues decreased in 2010 primarily due to the decrease in
our realized natural gas prices and natural gas production, as well as higher crude
oil royalties. partially offsetting these decreases were increases in the realized
price and production of crude oil as well as increased prices and volumes of
condensate blended with heavy oil consistent with increases in our production.
Our refining and Marketing net revenues for 2010 increased primarily because
of higher refined product prices and higher prices and volumes related to
operational third party sales undertaken by the marketing group, partially
offset by reduced refined products volumes from planned turnarounds,
a power outage and refinery optimization activities. Also increasing net
revenues in 2010, were unrealized hedging gains on natural gas.
Further information and explanations regarding our net revenues can be found in
the Operating Segments and Corporate and Eliminations sections of this MD&A.
O P E r At I n G C A s H F L OW
( $ m i lli o n s)
Crude Oil and NGLs
Oil Sands
Conventional Crude Oil and NGLs
Natural Gas
Other Upstream Operations
refining and Marketing
Operating Cash Flow
2010
2009
2008
$
1,052
$
1,002
$
751
1,081
16
2,900
75
753
2,061
5
3,821
368
1,019
1,033
2,227
13
4,292
(359)
$
2,975
$
4,189
$
3,933
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 42
Operating cash flow is a non-GAAp measure defined as net revenues less
production and mineral taxes, transportation and blending, operating and
purchased product expenses. It is used to provide a consistent measure of the
cash generating performance of our assets and improves the comparability
of our underlying financial performance between years. Operating cash flow
includes realized hedging gains and losses but excludes unrealized hedging
gains and losses which are included in the Corporate and Eliminations segment.
Operating cash flow decreased by $1,214 million in 2010 primarily because
of a $980 million reduction related to natural gas as a result of a 34 percent
decrease in realized prices along with lower production volumes. Crude
Oil and NGLs operating cash flow increased $48 million in 2010 as higher
production and realized prices were partially offset by higher operating
expenses consistent with increased production and higher royalties, mainly
due to Foster Creek achieving payout status for royalty purposes in 2010.
Operating cash flow for refining and Marketing decreased $293 million due to
increased crude oil purchased product costs and reduced crude utilization as a
result of planned turnarounds, a power outage and refinery optimization activities
related to weaker diesel and gasoline prices primarily in the first half of 2010.
Details of the components that explain the decrease in operating cash flow
can be found in the Operating Segments section of this MD&A.
C A s H F L OW
Cash flow is a non-GAAp measure defined as cash from operating activities
excluding net change in other assets and liabilities and net change in non-cash
working capital. Cash flow is commonly used in the oil and gas industry to assist
in measuring the ability to finance capital programs and meet financial obligations.
( $ m i lli o n s)
Cash From Operating Activities
(Add back) deduct:
Net change in other assets and liabilities
Net change in non-cash working capital
Cash Flow
Operating cash flow 2010
($ millions)
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
4,189
50
(2)
(980)
11
(293)
2,975
9
0
0
2
,
1
3
R
E
B
M
E
C
E
D
S
L
G
N
D
N
A
L
I
O
E
D
U
R
C
S
D
N
A
S
L
I
O
S
L
G
N
D
N
A
L
I
O
E
D
U
R
C
I
L
A
N
O
T
N
E
V
N
O
C
S
A
G
L
A
R
U
T
A
N
I
S
N
O
T
A
R
E
P
O
M
A
E
R
T
S
P
U
R
E
H
T
O
Y E A R E N D
I N C R E A S E S
D E C R E A S E S
I
G
N
T
E
K
R
A
M
D
N
A
G
N
N
I
F
E
R
I
0
1
0
2
,
1
3
R
E
B
M
E
C
E
D
2010
2009
2008
$
2,594
$
3,039
$
3,225
(55)
234
(26)
220
(92)
202
$
2,415
$
2,845
$
3,115
43 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Cash flow 2010
($ millions)
3,500
3,000
2,500
2,000
1,500
1,000
500
0
315
(754)
2,845
(136)
(181)
(170)
(293)
852
(63)
2,415
S
E
C
I
R
P
D
E
Z
I
L
A
E
R
S
A
G
L
A
R
U
T
A
N
S
L
G
N
D
N
A
L
I
O
E
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I N C R E A S E S
D E C R E A S E S
• An increase in general and administrative and net interest expense of
$75 million;
• Higher crude oil and NGLs operating expenses consistent with the increase
in production; and
• realized foreign exchange losses of $18 million in 2010 compared to gains
of $23 million in 2009.
The decreases in our 2010 cash flow were partially offset by:
• A $852 million decrease in current income tax expense as a result of 2009
including acceleration of current income tax along with 2010 including
the utilization of claims from tax pools that we received as a result of the
Arrangement, as well as lower realized hedging gains in 2010;
• A seven percent increase in our average realized liquids price to $62.60 per
bbl compared to $58.24 per bbl; and
• A six percent increase in our crude oil and NGLs production volumes.
In 2009, our cash flow decreased $270 million compared to 2008 as a result of:
• Current income tax expense increased $565 million primarily due to
accelerated income tax as a result of the dissolution of a partnership as
part of the Arrangement;
• A decrease in the realized average liquids selling price, including the impact
In 2010 our cash flow decreased $430 million from 2009 primarily due to:
of hedges, of $14.25 per bbl to $58.24 per bbl;
• A 34 percent decrease in the average realized natural gas price to
• Natural gas production declined 12 percent; and
$5.16 per Mcf compared to $7.78 per Mcf;
• A decrease in operating cash flow from refining and Marketing of $293 million
mainly due to planned turnarounds at both refineries, higher crude costs
and refinery optimization activities due primarily to weak diesel and
gasoline prices in the first half of 2010. partially offsetting these decreases
to operating cash flow was a strengthening of the Canadian dollar;
• An increase in crude oil and NGLs royalties of $181 million primarily as a
result of Foster Creek achieving project payout status for royalty purposes
as well as higher WTI prices partially offset by a strengthened average
Canadian dollar used for calculating royalties;
• Natural gas production in total declining 12 percent as a result of the
divestiture of certain non-core properties, which made up four percent of
the total annual decrease, as well as reduced capital expenditures;
O P E r At I nG E A r n I nGs
( $ m i lli o n s)
Net Earnings
(Add back) deduct:
Unrealized mark-to-market accounting gains (losses), after-tax (1)
Non-operating foreign exchange gains (losses), after-tax (2)
Gain on bargain purchase, after-tax
Operating Earnings
• A decrease in the realized average natural gas price, including the impact of
hedges, to $7.78 per Mcf compared to $7.93 per Mcf.
The 2009 cash flow decreases above were partially offset by:
• An improvement in our operating cash flow from refining and Marketing of
$727 million;
• A decrease in royalties of $260 million resulting from decreased
commodity sales prices;
• An eight percent increase in our crude oil and NGLs production volumes; and
• realized foreign exchange gains of $23 million in 2009 compared to losses
of $9 million in 2008.
2010
2009
2008
$
993
$
818
$
2,526
34
153
12
(494)
(210)
–
636
270
–
$
794
$
1,522
$
1,620
(1) The unrealized mark-to-market accounting gains (losses), after-tax includes the reversal of unrealized gains (losses) recognized in prior periods.
(2) After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the partnership contribution receivable, after-tax foreign exchange gains (losses)
on settlement of intercompany transactions and future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 44
Operating earnings is a non-GAAp measure defined as net earnings excluding
the after-tax gain (loss) on discontinuance; after-tax gain on bargain purchase;
after-tax effect of unrealized mark-to-market accounting gains (losses) on
derivative instruments; after-tax gains (losses) on non-operating foreign
exchange and the effect of changes in statutory income tax rates.
We believe that these non-operating items reduce the comparability of our
underlying financial performance between periods. The above reconciliation
of operating earnings has been prepared to provide information that is more
comparable between periods. The items identified above that affected our
cash flow and identified below that affected our net earnings also impacted
our operating earnings.
The decline in operating earnings for 2010 is consistent with the decreases to
our operating cash flow and cash flow, details of which can be found above,
partially offset by a decrease in depreciation, depletion and amortization
(“DD&A”) expense.
n E t E A r n I n G s v A r I A n C E
( $ m i lli o n s)
Net Earnings for the Year Ended December 31, 2009
$
818
Increase (decrease) due to:
Operating Segments
Upstream net revenues
Upstream expenses (1)
Upstream operating cash flow
refining and Marketing operating cash flow
Corporate and Eliminations
Unrealized hedging gains (losses), net of tax
Unrealized foreign exchange gains (losses)
Expenses (2)
Depreciation, depletion and amortization
Income taxes, excluding income taxes on unrealized hedging gains (losses)
$
(564)
(357)
(921)
(293)
528
396
(142)
217
390
net Earnings for the Year Ended December 31, 2010
$
993
(1) Includes production and mineral tax, transportation and blending and operating expenses.
(2) Includes general and administrative, net interest, accretion of asset retirement obligations, realized foreign exchange (gains) losses, gain (loss) on divestiture of assets, other (income) loss, net and
Corporate operating and purchased product expenses excluding unrealized hedging.
In 2010, net earnings increased by $175 million. The items identified above
that reduced our cash flow in 2010 also reduced our net earnings. Other
significant factors that impacted 2010 net earnings include:
• Unrealized mark-to-market hedging gains, after-tax, of $34 million,
compared to losses of $494 million, after-tax, in 2009;
• Unrealized foreign exchange gains of $69 million in 2010 compared to
• DD&A expense increasing by $130 million;
• Unrealized foreign exchange losses of $327 million for 2009 compared to
gains of $317 million in 2008; and
• Future income tax recovery, excluding the impact of the unrealized
financial hedging gains and losses, of $386 million, compared to future
income tax expense of $142 million in 2008.
losses of $327 million in 2009;
• A decrease of $217 million in DD&A; and
• Future income tax expense, excluding the impact of the unrealized
financial hedging gains, in 2010 of $76 million, compared to a recovery
of $386 million in 2009.
In 2009, net earnings decreased $1,708 million compared to 2008. The items
previously discussed that reduced our cash flow in 2009 also reduced our net
earnings. Other significant factors that impacted our 2009 net earnings include:
• Unrealized mark-to-market hedging losses, after-tax, of $494 million
compared to gains, after-tax of $636 million in 2008;
h E d g i n g i M P aC t O n n E t E a R n i n g S
As a means of managing the volatility of commodity prices, we enter into
various financial instrument agreements. Our strategy is to use financial
instruments to protect and provide certainty on a portion of our cash flows.
Changes in mark-to-market gains or losses on these agreements affect our net
earnings and are the result of volatility in the forward commodity prices and
changes in the balance of unsettled contracts.
45 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
( $ m i lli o n s)
Unrealized Mark-to-Market Hedging Gains (Losses), after-tax (1)
realized Hedging Gains (Losses), after-tax (2)
Hedging Impacts in Net Earnings
2010
2009
2008
$
$
34
199
233
$
$
(494)
804
310
$
$
636
(196)
440
(1) Included in Corporate and Eliminations financial results. Further detail on unrealized mark-to-market gains (losses) can be found in the Corporate and Eliminations section of this MD&A.
(2) Included in the Operating Segment financial results and included in operating cash flow and cash flow.
n E t C A P I tA L I n v E s t m E n t
( $ m i lli o n s)
Upstream
Oil Sands
Conventional
refining and Marketing
Corporate
Capital Investment
Acquisitions
Divestitures
Net Capital Investment
2010
2009
2008
$
$
867
523
1,390
656
76
2,122
86
(307)
629
466
1,095
1,033
34
2,162
3
(222)
$
758
848
1,606
539
59
2,204
–
(48)
$
1,901
$
1,943
$
2,156
Upstream capital investment in 2010 was primarily focused on continued
development of our oil sands projects and conventional oil properties,
including the drilling of stratigraphic wells to support the next phases of our
expansion activities. refining and Marketing capital investment was primarily
focused on the COrE project at the Wood river refinery. Capital investment
was funded by cash flow. Further information regarding our capital
investment can be found in the Operating Segments section of this MD&A.
aC q U i S i t i O n S a n d d i v E S t i t U R E S
Our planned program to divest of non-core oil and gas assets in 2010 resulted
in proceeds of $307 million. These divestitures included certain non-core
conventional crude oil and natural gas producing properties as well as the
sale of certain lands at the Narrows Lake property to the FCCL partnership.
Our 2010 acquisitions included the purchase of an interest in three
sections of undeveloped land at Narrows Lake as well as certain producing
conventional oil properties. In the fourth quarter of 2010 under the terms
of an agreement with an unrelated Canadian company, we acquired certain
marine terminal facilities in Kitimat, British Columbia for $38 million.
F r E E C A s H F L OW
In order to determine the funds available for financing and investing activities, including dividend payments, we use a non-GAAp measure of free cash flow, which
is defined as cash flow in excess of capital investment, which excludes acquisitions and divestitures. Cash flow is a non-GAAp measure and is defined under the
cash flow section of this MD&A.
( $ m i lli o n s)
Cash Flow
Capital Investment
Free Cash Flow
2010
2,415
2,122
293
$
$
2009
2,845
2,162
2008
$
3,115
2,204
683
$
911
$
$
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 46
results of Operations
C R U d E O i l a n d n g l S P R O d U C t i O n vO l U M E S
( b b l s /d )
Oil Sands – Heavy Oil
Foster Creek
Christina Lake
pelican Lake
Senlac
Conventional Liquids
Heavy Oil
Light and Medium Oil
NGLs (1)
(1) NGLs include condensate volumes.
2010
51,147
7,898
22,966
–
16,659
29,346
1,171
129,187
2010 vs
2009
36%
18%
-8%
–
-7%
-3%
-3%
6%
2009
37,725
6,698
24,870
3,057
17,888
30,394
1,206
121,838
2009 vs
2008
44%
57%
-9%
-5%
-6%
-3%
–%
8%
2008
26,220
4,279
27,324
3,223
19,062
31,492
1,203
112,803
Overall, our crude oil and NGLs production increased six percent in 2010.
Increases in production volumes at Foster Creek and Christina Lake were
partially offset by expected natural declines at our other properties. We also
sold certain non-core Conventional properties in 2010 which decreased our
total annual crude oil production by 975 bbls/d or one percent. In 2009, we
also sold our Senlac property. Further detail on the changes in our production
can be found in the Operating Segments section of this MD&A.
n at U R a l g a S P R O d U C t i O n vO l U M E S
( M M c f/d )
Conventional
Oil Sands
2010
694
43
737
2010 vs
2009
-11%
-19%
-12%
2009
784
53
837
2009 vs
2008
-9%
-40%
-12%
2008
866
88
954
47 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
During 2009 and 2010, we chose to restrict capital spending on natural gas
drilling, completion and tie-in activity in favour of increasing investment
in crude oil projects. In 2010, we divested of certain non-core natural gas
properties which decreased annual production by approximately 33 MMcf/d,
or four percent. Weather related delays experienced throughout 2010 also
negatively impacted our natural gas production.
On a barrel of oil equivalent basis, excluding the divestitures, production
remained consistent in 2010 compared to 2009. Further details on the changes in
our production can be found in the Operating Segments section of this MD&A.
O P E R at i n g n E t B aC k S
2010
2009
2008
Liquids natural Gas
($/mcf)
($/bbl)
Liquids
($/bbl)
Natural Gas
($/Mcf)
Liquids
($/bbl)
Natural Gas
($/Mcf)
price (1)
royalties
production and mineral taxes
Transportation and blending (1)
Operating expenses
Netback excluding realized Financial Hedging
realized Financial Hedging Gains (Losses)
$
62.96
$
9.33
0.62
1.88
11.78
39.35
(0.36)
4.09
0.07
0.02
0.17
0.96
2.87
1.07
$
57.14
5.62
0.65
1.60
10.67
38.60
1.10
$
4.15
0.08
0.05
0.15
0.86
3.01
3.63
$
77.84
$
9.32
1.01
1.62
10.90
54.99
(5.35)
8.17
0.42
0.11
0.24
0.84
6.56
(0.24)
Netback including realized Financial Hedging
$
38.99
$
3.94
$
39.70
$
6.64
$
49.64
$
6.32
(1) Operating netbacks for liquids exclude the value of condensate sold as bitumen blend and condensate costs recorded in transportation and blending expense.
In 2010, our average netback for liquids, excluding realized financial hedging,
increased by $0.75 per bbl primarily due to an increase in prices partially
offset by higher royalties and operating expenses. Our average netback for
natural gas, excluding realized financial hedges, decreased by $0.14 per Mcf
primarily as a result of lower sales prices and increased operating expenses
per Mcf as natural gas production decreased while operating expenses were
relatively consistent. Further discussions of operating results are contained in
the Operating Segments section of this MD&A.
As part of ongoing efforts to maintain financial resilience and flexibility, we
reduced our price risk through a commodity price hedging program. Our
strategy is to protect a significant portion of the subsequent years’ cash
flows through the use of various financial instruments. Further information
regarding this program can be found in the notes to the Consolidated
Financial Statements.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 48
Operating segments
Our Upstream Segment has two reportable operations: Oil Sands and
Conventional. Oil Sands consists of our producing bitumen assets at Foster
Creek and Christina Lake, heavy oil assets at pelican Lake, the new resource
play assets such as our Narrows Lake, Grand rapids and Telephone Lake
properties as well as the Athabasca natural gas assets. Conventional includes
the development and production of crude oil, natural gas and NGLs in western
Canada. The refining and Marketing segment includes our ownership interest
in the Wood river and Borger refineries and the marketing of our crude oil
and natural gas, as well as third-party purchases and sales of product.
u P s t rE A m
O i l S a n d S
In northeast Alberta, we are a 50 percent partner in the Foster Creek and
Christina Lake oil sands projects and also produce heavy oil from our pelican
Lake operations. prior to its divestiture in the fourth quarter of 2009, we
also owned 100 percent of the Senlac property. We also have several new
resource plays in the early stages of assessment, including Narrows Lake,
Grand rapids and Telephone Lake. The Oil Sands assets also include the
Athabasca natural gas property from which a portion of the natural gas
production is used as fuel at the adjacent Foster Creek operations.
Oil Sands highlights in 2010 include:
• Foster Creek achieving project payout status for royalty purposes in 2010;
• receiving regulatory approval for the next three phases of expansion (F, G
and H) at Foster Creek;
• Significant increases in production at Foster Creek and Christina Lake;
• Filing a joint application and EIA for our Narrows Lake project;
• receiving approval for and commencing a pilot project at our Grand rapids
property; and
• Completing a large stratigraphic well program in 2010 and commencing
a winter stratigraphic well program targeting to drill approximately
450 wells in 2011.
O i l S a n d S – C R U d E O i l
Financial results
( $ m i lli o n s)
revenues
Deduct (add)
realized financial hedging (gains) losses
royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
Operating Cash Flow
Capital Investment
2010
2009
2008
$
2,611
$
2,008
$
2,337
8
276
2,327
–
934
341
1,052
867
(48)
129
75
178
1,927
2,084
1
626
298
1,002
629
373
2
784
279
1,019
758
261
$
Operating Cash Flow in Excess of related Capital
$
185
$
49 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
production Volumes
C r u d e o i l ( b b l s /d )
Foster Creek
Christina Lake
Total
pelican Lake
Senlac
2010
51,147
7,898
59,045
22,966
–
82,011
2010 vs
2009
36%
18%
33%
-8%
–
13%
2009
37,725
6,698
44,423
24,870
3,057
72,350
2009 vs
2008
44%
57%
46%
-9%
-5%
19%
2008
26,220
4,279
30,499
27,324
3,223
61,046
Foster Creek and Christina Lake Production Volumes by Quarter
(bbls/d)
F O ST E R C R E E K
C H R I ST I N A L A K E
65,000
60,000
55,000
50,000
45,000
40,000
35,000
30,000
25,000
20,000
15,000
10,000
5,000
0
Q4
2008
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2009
2010
Net revenues Variance
( $ m i lli o n s)
Crude Oil
2009 Net
revenues
Net revenues Variances in:
price (1)
Volume
royalties Condensate(2)
2010 net
revenues
$
1,927
80
178
(147)
289
$
2,327
(1) Includes the impact of realized financial hedging.
(2) revenue dollars reported include the value of condensate sold as bitumen blend. Condensate costs are recorded in transportation and blending expense.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 50
In 2010 our average crude oil sales price, excluding realized financial hedges,
increased eight percent to $59.76 per bbl compared to 2009 consistent with
the WCS benchmark increasing year over year. Financial hedging activities
for 2010 resulted in realized losses of $8 million ($0.26 per bbl) compared
to gains of $48 million ($1.87 per bbl) in 2009 (2008–losses of $75 million;
$3.37 per bbl).
Foster Creek production increased 36 percent primarily as a result of the
phase D and E expansions, which commenced production late in the first
quarter of 2009, as well as increased production from wedge wells. The
18 percent increase in production at Christina Lake was a result of increased
production from the phase B expansion, well optimizations and production
from the first wedge well at Christina Lake. At pelican Lake, the decrease in
production was the result of expected natural production declines. In the
fourth quarter of 2009, we sold our Senlac heavy oil assets which had annual
production of 3,057 bbls/d in 2009. pipeline apportionments in the second
half of 2010 did not significantly affect our production but did result in lower
sales volumes and higher volumes in storage at the end of 2010.
royalties increased by $147 million in 2010 compared to 2009 due to Foster
Creek achieving project payout status for royalty purposes in the first quarter
of 2010, along with an increased WTI price partially offset by a strengthened
Canadian dollar used for calculating royalties, resulting in higher royalty
rates. For 2010, the effective royalty rate for Foster Creek was 16.2 percent
(2009–2.7 percent; 2008–1.1 percent) and for Christina Lake was 3.9 percent
(2009–2.3 percent; 2008–1.0 percent). pelican Lake royalties remained
consistent as the increase in royalty rates due to higher prices was offset
O i l S a n d S – C a P i ta l i n v E S t M E n t
by lower volumes, which resulted in an effective royalty rate of 21.1 percent
(2009–20.1 percent; 2008–20.2 percent).
Transportation and condensate blending costs increased by $308 million
in 2010. The increase in condensate blending costs of $289 million was
primarily related to the volume of condensate required increasing due to
higher production at Foster Creek and Christina Lake as well as an increase
in the average cost of condensate, while blending costs at pelican Lake were
consistent with 2009. Transportation costs increased $19 million primarily due
to the higher production volumes.
Operating costs increased by $43 million due to higher repairs and
maintenance, increased field personnel in relation to phased expansions,
higher chemical costs and purchased fuel volumes in relation to production
increases. The increase in operating costs at Foster Creek and Christina Lake
is due to a 33 percent increase in production volumes. At pelican Lake, the
increase in operating costs is attributable to polymer chemical costs and
increased maintenance and workover expenses.
O i l S a n d S – n at U R a l g a S
Oil Sands also includes our 100 percent owned natural gas operations in
Athabasca. primarily as a result of natural declines, our natural gas production
decreased to 43 MMcf/d (2009–53 MMcf/d; 2008–88 MMcf/d). As a result of
lower production as well as lower natural gas prices, operating cash flow declined
$104 million in 2010 to $77 million (2009–$181 million; 2008–$160 million).
( $ m i lli o n s)
Foster Creek
Christina Lake
Total
pelican Lake
New resource plays
Other (1)
(1) Includes Athabasca and Senlac.
2010
2009
2008
$
$
278
346
624
104
124
15
$
262
224
486
72
17
54
356
235
591
62
53
52
$
867
$
629
$
758
51 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Our Oil Sands capital investment in 2010 was primarily focused on the
continued development of the next expansion phases of the Foster Creek and
Christina Lake projects, as well as activities related to our pelican Lake polymer
flood. Our current plan is to increase gross production capacity at Foster
Creek and Christina Lake to approximately 218,000 bbls/d of bitumen with the
expected completion of Christina Lake phase C in 2011 and phase D in 2013.
Foster Creek capital investment in 2010 was higher as we received regulatory
approval for the next phases of expansion (F, G and H). The majority of Foster
Creek spending was related to drilling stratigraphic test wells, debottlenecking
portions of the plant and preparation for the next phases of expansion
including engineering and design, site preparation and camp construction.
We are planning to accelerate the completion of Foster Creek phase F by up
to 12 months which would result in production beginning in 2014.
At Christina Lake, capital investment was higher in 2010 due to construction
and well pad drilling related to the phase C expansion, detailed design,
procurement and construction for the phase D expansion and the drilling
of stratigraphic test wells. We have chosen to accelerate completion of
Christina Lake phase D by approximately six months and expect production
to begin in 2013. Our current plan is to increase gross production capacity to
approximately 98,000 bbls/d of bitumen with the expected completion of
phase C in 2011 and phase D in 2013.
Capital investment for pelican Lake was primarily related to capital maintenance,
facility additions for polymer flooding and infill drilling opportunities.
Capital investment in new resource plays in 2010 was mainly related to the
drilling of stratigraphic test wells, as shown in the following table, regulatory
advancement and the Grand rapids pilot project including the drilling of a
SAGD well pair and facility construction.
Gross Stratigraphic Wells
The stratigraphic test wells drilled at Foster Creek and Christina Lake are to support the next phases of expansion while the stratigraphic test wells drilled at
Narrows Lake, Grand rapids, Telephone Lake and other emerging projects have been drilled to assess the quality of our projects and to support regulatory
applications for project approval.
Foster Creek
Christina Lake
Total
Narrows Lake
Grand rapids
Telephone Lake
Other
C O n v E n t i O n a l
2010
2009
2008
82
24
106
39
71
26
17
259
65
28
93
–
17
–
–
110
144
113
257
–
8
5
5
275
Our Conventional operations include the development and production
of crude oil, natural gas and NGLs in Alberta and Saskatchewan. These
conventional crude oil and natural gas assets generate reliable production
and cash flows.
Conventional highlights in 2010 include:
• Generating operating cash flow in excess of capital investment of more
than $1.2 billion;
• recompleted 1,194 Alberta natural gas wells adding low cost production;
• Weyburn production increasing as a result of our well optimization
program, which partially offset natural declines;
• The continued development of the Bakken and Shaunavon plays where we
more than doubled average production to about 2,000 bbls/d from less
than 1,000 bbls/d in 2009; and
• Divesting of certain non-core properties for proceeds of $221 million,
which reduced our annual crude oil and NGLs production volume two
percent and our annual natural gas production volume four percent.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 52
C R U d E O i l a n d n g l S
Financial results
( $ m i lli o n s)
revenues
Deduct (add)
realized financial hedging (gains) losses
royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
Operating Cash Flow
Capital Investment
2010
2009
2008
$
1,229
$
1,161
$
1,752
9
153
–
119
1,067
1,042
28
86
202
751
358
393
$
28
87
174
753
223
530
$
146
208
1,398
40
154
171
1,033
359
674
Operating Cash Flow in Excess of related Capital
$
production Volumes
( b b l s /d )
Heavy Oil
Alberta
Light and Medium Oil
Alberta
Saskatchewan
NGLs
2010
16,659
10,854
18,492
1,171
47,176
2010 vs
2009
2009
2009 vs
2008
2008
-7%
-9%
–%
-3%
-5%
17,888
-6%
19,062
11,959
18,435
1,206
49,488
-14%
5%
–%
-4%
13,941
17,551
1,203
51,757
53 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Net revenues Variance
Net Revenues Variance
($ millions)
1,500
1,000
1,042
500
0
9
0
0
2
,
1
3
R
E
B
M
E
C
E
D
133
(76)
(34)
2
1,067
)
1
(
E
C
I
R
P
E
M
U
L
O
V
S
E
I
T
L
A
Y
O
R
)
2
(
E
T
A
S
N
E
D
N
O
C
0
1
0
2
,
1
3
R
E
B
M
E
C
E
D
Y E A R E N D
I N C R E A S E S
D E C R E A S E S
(1) Includes the impact of realized financial hedging.
(2) revenue dollars reported include the value of condensate sold as heavy oil blend. Condensate
costs are recorded in transportation and blending expense.
For 2010 the average crude oil and NGLs sales price, excluding realized
hedging, increased 14 percent to $68.45 per bbl, consistent with the increases in
benchmark prices. During 2010, realized financial hedging losses were $9 million
($0.54 per bbl) compared to gains of less than $1 million ($0.02 per bbl) in 2009
(2008–losses of $146 million; $7.67 per bbl).
n at U R a l g a S
Financial results
( $ m i lli o n s)
revenues
Deduct (add)
realized financial hedging (gains) losses
royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
Operating Cash Flow
Capital Investment
production in 2010 was lower than 2009 due to expected natural declines,
the divestiture of non-core producing properties in the first half of 2010
(which had an annual average production of approximately 1,000 bbls/d),
production downtime due to weather and operational challenges in Alberta
and Saskatchewan. pipeline apportionments in the second half of 2010 did
not significantly affect our production but did result in lower heavy oil
sales prices as well as lower sales volumes and higher volumes in storage
at the end of 2010. partially offsetting these reductions was increased
production from well optimizations at Weyburn and new wells in Alberta and
Saskatchewan, including increased production at Bakken and Shaunavon.
royalties for 2010 were $34 million higher as a result of higher commodity
prices, as well as higher royalty rates arising from the higher commodity
prices, which resulted in an effective royalty rate of 13.3 percent for 2010
(2009–11.4 percent; 2008–13.0 percent). The higher royalty rate was partially
offset by lower volumes.
production and mineral taxes were consistent in 2010 as higher commodity
prices were offset by a prior period adjustment that had increased expenses
in 2009.
Transportation and blending costs were consistent in 2010 as increases in the
average cost of condensate were offset by decreased volumes of condensate
required for blending with heavy oil.
Operating costs increased $28 million in 2010 primarily from increased
workover activity mainly at Weyburn, higher repair and maintenance activity
in all areas, higher trucking costs related to new production in Saskatchewan
and higher indirect costs.
Our Conventional crude oil and NGLs operations generated $393 million of
operating cash flow in excess of capital investment, a decrease of $137 million
from 2009 mainly due to increased capital investment in 2010.
2010
2009
2008
$
1,042
$
1,189
$
2,588
(264)
17
1,289
6
44
235
1,004
165
839
(1,007)
19
2,177
15
45
237
1,880
243
76
79
2,433
38
76
252
2,067
489
$
1,637
$
1,578
Operating Cash Flow in Excess of related Capital
$
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 54
Net revenues Variance
Net Revenues Variance
($ millions)
2,500
2,000
1,500
1,000
500
0
2,177
(754)
(136)
2
1,289
9
0
0
2
,
1
3
R
E
B
M
E
C
E
D
)
1
(
E
C
I
R
P
E
M
U
L
O
V
S
E
I
T
L
A
Y
O
R
0
1
0
2
,
1
3
R
E
B
M
E
C
E
D
Y E A R E N D
I N C R E A S E S
D E C R E A S E S
(1) Includes the impact of realized financial hedging.
Our natural gas revenue and operating cash flow is down significantly due to
lower realized prices. While our average natural gas price, excluding realized
financial hedges, decreased slightly compared to 2009 and was consistent
with the change in benchmark AECO price, the most significant decline in
our revenue is a $743 million decline related to our realized financial hedging
C O n v E n t i O n a l – C a P i ta l i n v E S t M E n t
( $ m i lli o n s)
Alberta
Saskatchewan
gains in 2010, which were $264 million ($1.04 per Mcf), compared to gains of
$1,007 million ($3.52 per Mcf) in 2009 (2008–losses of $76 million; $0.24 per Mcf)
as a result of our settled fixed price contracts being approximately $3.00 per Mcf
lower than the same period in 2009 due to the oversupply of natural gas
and weaker market prices. For details of the specific pricing on our hedging
program, see the notes to our Consolidated Financial Statements.
The cumulative impact of restricted natural gas capital spending in 2009 and
2010 as well as divestitures of non-core properties and natural production
declines reduced our natural gas production volumes by 11 percent to 694
MMcf/d in 2010 (2009–784 MMcf/d; 2008–866 MMcf/d). The divestitures
reduced our 2010 annual natural gas production by approximately 33 MMcf/d.
royalties were slightly lower in 2010 as a result of adjustments related to
prior years’ production partially offset by lower volumes. The average royalty
rate for 2010 was 1.7 percent (2009–1.6 percent; 2008–3.1 percent).
production and mineral taxes in 2010 were $9 million lower than 2009 mainly
due to lower prices and volumes in 2010.
Costs related to transportation decreased slightly in 2010 due to lower volumes.
Operating expenses for 2010 decreased slightly as a result of reduced
operations due to divestitures and lower production volumes. These declines
were specifically related to lower property tax, repairs and maintenance,
lower field staff and salaries as well as lower chemical costs, were offset with
increased electricity prices and higher indirect costs.
Our Conventional natural gas operations generated $839 million of operating
cash flow in excess of capital investment, a decrease of $798 million from
2009 mainly due to lower realized prices in 2010.
2010
2009
2008
$
$
303
220
523
$
$
340
126
466
$
$
598
250
848
For 2010, approximately 68 percent or $358 million of our capital investment
was on our crude oil properties (2009–48 percent or $223 million; 2008–
42 percent or $359 million). Capital investment in Alberta was focused on our
oil program, our shallow gas projects and our liquids rich deep gas projects.
Our capital investment in Saskatchewan continued to focus on drilling and
facility work at Weyburn as well as appraisal projects at Lower Shaunavon
and Bakken. In 2010, we drilled 36 wells in the Shaunavon and Bakken areas,
22 of which were on production at the end of 2010.
The following table details our Conventional drilling activity. Fewer natural gas
wells were drilled in 2010 as our drilling program shifted towards oil wells from
shallow gas wells. Well recompletions are mostly related to CBM development.
(n e t w e ll s)
Crude oil
Natural gas
recompletions
Stratigraphic test wells
2010
180
495
1,194
9
2009
2008
105
502
855
5
93
1,375
1,017
13
55 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
r E F I n I n G A n D m A r k E t I n G
This operating segment includes the results of our refining operations in the
U.S. that are jointly owned with and operated by Conocophillips. This segment’s
results also include the marketing group’s third party purchases and sales
of product, undertaken to provide operational flexibility for transportation
commitments, product quality, delivery points and customer diversification.
refining and Marketing highlights in 2010 include:
• The progression of the COrE project to approximately 91 percent
complete from 71 percent at the beginning of the year; and
• Operating cash flow increasing in the fourth quarter by $112 million due
to higher market crack spreads and increased utilization compared to the
fourth quarter of 2009.
Financial results
( $ m i lli o n s)
revenues
purchased product
Gross margin
Operating expenses
Operating Cash Flow
Capital Investment
2010
$
8,228
$
7,664
564
489
75
656
2009
6,922
6,020
902
534
368
1,033
2008
$
10,684
10,500
184
543
(359)
539
Capital Investment in Excess of Operating Cash Flow
$
(581)
$
(665)
$
(898)
refining and Marketing revenues in 2010 increased 19 percent primarily due to
higher prices for refined products and crude oil, as well as higher marketing
volumes related to operational third-party sales.
times between the purchases of a portion of our Canadian heavy oil and the
processing at the refinery and resulted in the product purchased in the third
quarter of 2010 to be processed in the fourth quarter of 2010.
purchased product costs, which are determined on a first-in, first-out
inventory valuation basis, increased 27 percent in 2010 due mainly to higher
crude costs and operational third-party marketing volumes.
Operating costs, consisting mainly of labour, utilities and supplies, decreased
eight percent in 2010 due to lower maintenance and decreased prices for
utilities consumed at the refineries and a strengthened Canadian dollar.
Our refining operations benefitted in the fourth quarter of 2010 from the
wider light-heavy crude oil price differentials that occurred in the third
quarter of 2010 as a result of pipeline disruptions. In addition, the initial start
up phase of the Keystone pipeline in 2010 resulted in lengthy transportation
2010 operating cash flow decreased by $293 million mainly due to planned
turnarounds at both refineries, higher average crude costs as well as refinery
optimization activities due primarily to weaker diesel and gasoline prices in
the first half of 2010. partially offsetting these decreases to operating cash
flow was a strengthening of the Canadian dollar.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 56
R E F i n E Ry O P E R at iO n S ( 1 )
Crude oil capacity (Mbbls/d)
Crude oil runs (Mbbls/d)
Crude utilization (%)
refined products (Mbbls/d)
2010
2009
2008
452
386
86
405
452
394
87
417
452
423
93
448
(1) represents 100% of the Wood river and Borger refinery operations.
On a 100 percent basis, our refineries have a current capacity of
approximately 452,000 bbls/d of crude oil and 45,000 bbls/d of NGLs,
including processing capability to refine up to 145,000 bbls/d of blended
heavy crude oil. Upon completion of the Wood river COrE project
we expect to be able to refine approximately 275,000 bbls/d (on a 100
percent basis) of heavy crude oil (approximately 150,000 bbls/d of bitumen
equivalent) primarily into motor fuels.
Our crude utilization was slightly lower in 2010 primarily due to a planned
turnaround at the Wood river refinery, an extended turnaround at the Borger
refinery, a power outage at Wood river, unplanned maintenance and refinery
optimization activities.
C a P i ta l i n v E S t M E n t
( $ m i lli o n s)
Wood river refinery
Borger refinery
Marketing
2010
2009
2008
$
568
$
944
$
87
1
88
1
$
656
$
1,033
$
477
45
17
539
Our refining capital investment in 2010 continued to focus on the COrE
project at the Wood river refinery. For 2010, of the $568 million capital
expenditures at the Wood river refinery, $473 million were related to the
COrE project. At December 31, 2010, the COrE project is approximately
91 percent complete. Unanticipated high water levels on the Mississippi river
caused delays in the delivery schedule of various modules, which resulted
in a shift to the timeline for this project. Commissioning of several of the
process units has been completed with an expected coker start up in the
fourth quarter of 2011. At the time of coker start up, we expect that COrE
expenditures will reach approximately US$3.7 billion (US$1.85 billion net to
Cenovus). The total estimated cost of the COrE project is expected to be
approximately US$3.9 billion (US$1.95 billion net to Cenovus), or about
10 percent higher than originally forecast.
The balance of the Wood river and Borger refineries 2010 capital investment
was related to refining reliability and maintenance projects, clean fuels and
other emission reduction environmental initiatives.
57 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Corporate and Eliminations
Financial results
( $ m i lli o n s)
revenues
Expenses (add) deduct
Operating
purchased product
2010
2009
2008
$
(64)
$
(778)
$
731
3
(115)
30
(110)
$
48
$
(698)
$
(13)
(159)
903
The Corporate and Eliminations segment includes revenues that represent
the unrealized mark-to-market gains and losses related to derivative financial
instruments used to mitigate fluctuations in commodity prices. The segment
also includes inter-segment eliminations that relate to transactions that have
been recorded at transfer prices based on current market prices as well as
unrealized intersegment profits in inventory. Operating expenses primarily
relate to unrealized mark-to-market gains and losses on long-term power
purchase contracts.
The Corporate and Eliminations segment also includes Cenovus-wide costs for
general and administrative and financing activities made up of the following:
( $ m i lli o n s)
General and administrative
Interest, net
Accretion of asset retirement obligation
Foreign exchange (gain) loss, net
(Gain) loss on divestiture of assets and other
2010
2009
2008
$
$
$
251
279
75
(51)
(4)
211
244
45
304
(2)
$
550
$
802
$
171
233
40
(308)
3
139
General and administrative expenses were $40 million higher in 2010 primarily
due to higher salaries and benefits as we move to implement our 10 year
strategic plan and complete the transition to a new independent company as
well as higher long-term incentive expense due to an increase in our share price.
Net interest in 2010 was $35 million higher than 2009 primarily as a result of
a full year of standby fees incurred on our committed credit facility in 2010
as well as a full year of amortization on financing costs related to the setup
of debt financing programs. Additionally, interest on long-term debt was
slightly higher in 2010 as a result of a higher average interest rate and higher
outstanding debt in 2010 compared to the proportionate share of Encana’s
debt allocated to Cenovus for the majority of 2009. The weighted average
interest rate on outstanding debt for the year ended December 31, 2010 was
5.8 percent (2009–5.5 percent; 2008–5.5 percent).
In 2010 we reported foreign exchange gains of $51 million (2009–losses
of $304 million; 2008–gains of $308 million), the majority of which were
unrealized. The strengthening of the Canadian dollar during 2010 led to
unrealized gains on our U.S. dollar debt, which was partially offset by
unrealized losses on our U.S. dollar partnership contribution receivable.
The 2010 gain on divestiture of assets and other includes a gain of $12 million
related to the acquisition of certain marine terminal facilities in Kitimat,
British Columbia in the fourth quarter of 2010.
Summary of Unrealized Mark-To-Market Gains (Losses)
The volatility of commodity prices has a significant impact on our net
earnings, and as a means of managing this volatility, we enter into various
financial instrument agreements. Our strategy is to use financial instruments
to protect and provide certainty on a portion of our cash flows. The financial
instrument agreements were recorded at the date of the financial statements
based on mark-to-market accounting. Changes in the mark-to-market gains
or losses reflected in corporate revenues are the result of volatility between
periods in the forward commodity prices and changes in the balance of
unsettled contracts. The table below provides a summary of the unrealized
mark-to-market gains and losses recognized for each period. Additional
information regarding financial instruments can be found in the notes to the
Consolidated Financial Statements.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 58
( $ m i lli o n s)
revenues
Crude Oil
Natural Gas
Expenses
Income Tax Expense (recovery)
Unrealized Mark-to-Market Gains (Losses), after-tax
d E P R E C i at i O n , d E P l E t i O n a n d a M O R t i Z at i O n
( $ m i lli o n s)
Upstream
refining and Marketing
Corporate and Eliminations
2010
2009
2008
$
$
$
(92)
152
60
14
46
12
34
$
(102)
(566)
(668)
30
(698)
(204)
$
(494)
$
260
630
890
(9)
899
263
636
2010
2009
2008
$
1,039
$
1,250
$
239
32
232
45
1,179
205
13
$
1,310
$
1,527
$
1,397
We use full cost accounting for our upstream oil and gas activities and
calculate DD&A on a country-by-country cost centre basis. Upstream DD&A
decreased in 2010 primarily as a result of a reduced DD&A rate with the
addition of proved reserves at Christina Lake phase D at the end of 2009.
refining and Marketing DD&A in 2010 includes an impairment loss of $37
million related to a processing unit determined to be a redundant asset and
which would not be used in future operations at the Borger refinery. Offsetting
this was lower DD&A on the refineries primarily related to a strengthening
of the average U.S./Canadian dollar exchange rate in 2010. Corporate and
Eliminations DD&A includes provisions in respect of corporate assets, such as
computer equipment, office furniture and leasehold improvements.
i n C O M E t a x
( $ m i lli o n s)
Current income tax expense
Future income tax expense (recovery)
Total Income taxes
When comparing 2010 to 2009, our current tax expense declined and our future
tax expense increased. Our current income tax expense in 2009 included the
acceleration of income tax incurred as a result of certain corporate restructuring
transactions which were required to give effect to the Arrangement and was
offset by a recovery of future income tax in 2009. Our future income tax expense
in 2010 includes a tax benefit of $107 million from the recognition of net capital
losses expected to be realized against future taxable capital gains. These capital
losses are attributable to an internal restructuring undertaken in 2010.
Our effective tax rate for 2010 was 14.6 percent compared to 29.6 percent
in 2009 (2008–23.5 percent). The decrease in 2010 is primarily due to the
recognition of the future tax benefits arising from net capital losses and from
operating losses in our U.S. entities in 2010 compared to earnings in 2009.
It should be noted that our 2009 income tax expense was calculated as if
Cenovus and its subsidiaries had been separate tax paying legal entities, each
filing a separate tax return in its local jurisdiction, and that the calculation
2010
2009
2008
$
$
82
88
170
$
$
934
(590)
344
$
$
369
405
774
was based on a number of assumptions, allocations and estimates consistent
with the historical carve-out consolidated financial statements.
Our effective tax rate in any year is a function of the relationship between
total tax expense and the amount of earnings before income taxes for the
year. The effective tax rate differs from the statutory tax rate as it takes
into consideration permanent differences, adjustments for changes in tax
rates and other tax legislation, variation in the estimate of reserves and the
differences between the provision and the actual amounts subsequently
reported on the tax returns. permanent differences include:
• The non-taxable portion of Canadian capital gains and losses;
• Multi-jurisdictional financing;
• Non-deductible stock-based compensation; and
• Taxable foreign exchange gains not included in net earnings.
Tax interpretations, regulations and legislation in the various jurisdictions in
which the Company and its subsidiaries operate are subject to change. We
believe that our provision for taxes is adequate.
59 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Quarterly Financial Data
( $ m i lli o n s , e x c e p t p e r s h a r e a m o u n t s)
Net revenues
Operating Cash Flow (1)
Cash Flow (1)
- per share – diluted (2)
Operating Earnings (1)
- per share – diluted (2)
Net Earnings
- per share – basic (2)
- per share – diluted (2)
Capital Investment
Free Cash Flow (1)
Cash Dividends (3)
- per share (3)
Q4
2010
Q3
2010
Q2
2010
Q1
2010
Q4
2009
Q3
2009
Q2
2009
Q1
2009
3,172
3,115
3,195
3,491
3,005
3,001
2,818
2,693
812
648
660
509
0.86
0.68
140
0.19
73
0.10
0.10
706
(58)
151
159
0.21
223
0.30
0.30
480
29
150
665
537
0.71
142
0.19
172
0.23
0.23
443
94
150
838
721
0.96
353
0.47
525
0.70
0.70
493
228
150
954
235
0.31
169
0.23
42
0.06
0.06
507
(272)
159
0.20
0.20
0.20
0.20
US$0.20
1,134
1,173
924
1.23
427
945
1.26
512
0.57
0.68
101
0.13
0.13
515
409
n/a
n/a
160
0.21
0.21
488
457
n/a
n/a
928
741
0.99
414
0.55
515
0.69
0.69
652
89
n/a
n/a
Q4
2008
3,946
121
(209)
(0.28)
(159)
(0.21)
490
0.65
0.65
760
(969)
n/a
n/a
(1) Non-GAAp measure defined within this MD&A.
(2) Any per share amounts prior to December 1, 2009 have been calculated using Encana’s common share balances based on the terms of the Arrangement, wherein Encana shareholders received one common
share of Cenovus and one common share of the new Encana.
(3) The fourth quarter 2009 dividend reflected an amount determined in connection with the Arrangement based on carve-out earnings and cash flow.
In the fourth quarter of 2010 cash flow increased $413 million compared to
the fourth quarter of 2009 primarily due to:
• A $526 million decrease in current income tax expense as a result of 2009
including acceleration of current income tax along with 2010 including
the utilization of claims from tax pools that we received as a result of the
Arrangement, as well as lower realized hedging gains in 2010; and
• A $112 million increase in operating cash flow from refining and Marketing
primarily due to higher market crack spreads and increased utilization
compared to the fourth quarter of 2009.
The increases in our fourth quarter 2010 cash flow were partially offset by:
• A 22 percent decrease in the average realized natural gas price to $5.05 per
Mcf from $6.44 per Mcf;
• A 14 percent decrease in natural gas production primarily due to the
disposition of certain non-core properties and reduced natural gas
capital expenditures;
• A five percent decrease in our average realized liquids price to
• Higher crude oil and NGLs operating costs consistent with the increase
in production;
• An increase in general and administrative and net interest expense of
$13 million; and
• An increase in royalties of $10 million primarily as a result of Foster Creek
achieving royalty payout as well as higher WTI prices partially offset by a
strengthened average Canadian dollar used for calculating royalties.
Our net earnings in the fourth quarter of 2010 were $31 million higher than
2009. The factors that increased our cash flow in the fourth quarter also
increased net earnings. Other significant factors that impacted our fourth
quarter 2010 net earnings include:
• Future income tax expense, excluding the impact of the unrealized financial
hedging gains, in 2010 of $37 million, compared to a recovery of $351 million
in 2009;
• Unrealized mark-to-market losses, after-tax, of $197 million, compared to
losses of $92 million, after-tax, in 2009;
$61.46 per bbl compared to $64.74 per bbl;
• Unrealized foreign exchange gains of $30 million in 2010 compared to
• A decrease in crude oil and NGLs volumes sold due to pipeline
apportionments in the fourth quarter of 2010;
losses of $86 million in 2009; and
• A decrease of $28 million in DD&A.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 60
Oil and Gas reserves and resources
As a Canadian issuer, we are subject to the reporting requirements of Canadian
securities regulatory authorities, including the reporting of our reserves
in accordance with National Instrument 51-101 Standards of Disclosure for
Oil and Gas Activities (“NI 51-101”). prior to the year ended December 31,
2010, we presented our reserves estimates in accordance with certain U.S.
disclosure requirements pursuant to an exemption from certain of the NI 51-101
requirements. Year over year comparisons are in reference to the previously
disclosed December 31, 2009 estimates prepared by independent qualified
reserves evaluators (“IQrEs”) and determined using 2009 12 month average
constant prices and costs, as prescribed by the U.S. Securities and Exchange
Commission (“SEC”).
We retain two IQrEs, McDaniel & Associates Consultants Ltd. (“McDaniel”)
and GLJ petroleum Consultants Ltd., to evaluate and prepare reports on 100
percent of our reserves. McDaniel also evaluated 100 percent of our bitumen
contingent and prospective resources.
The reserves Committee of the Board, composed of independent directors,
annually reviews the qualifications and selection of the IQrEs, the procedures
relating to the disclosure of information with respect to oil and gas activities
and the procedures for providing information to the IQrEs. The reserves
Committee meets with management and each IQrE to determine whether
any restrictions affect the ability of the IQrE to report on the reserves data
without reservation, to review the reserves data and the report of the IQrE
thereon, and to recommend approval of the reserves and resources disclosure
to the Board.
Highlights in 2010 include:
• Improved recovery factor and expansion of development area at Foster Creek
led to substantial growth in our proved bitumen reserves by 288 MMbbls,
a 33 percent increase from 2009;
• Conventional oil and NGLs proved reserves grew one percent; and
• An overall nine percent decline in natural gas and CBM proved reserves due
to extensions and improved recoveries as well as technical revisions not
enough to offset production and dispositions.
The reserves data presented summarizes our bitumen, heavy oil, light and
medium oil plus NGLs, and natural gas plus CBM reserves using McDaniel’s
January 1, 2011 forecast prices and costs. We hold significant freehold title
rights which generate production for our account from third parties leasing
those lands. The before royalty volumes presented below do not include
reserves associated with this production.
Information with respect to pricing as well as additional reserves information is
contained in our Annual Information Form (“AIF”) for the year ended December
31, 2010, available at www.sedar.com and on our website at www.cenovus.com.
r E s E rv E s A t D E C E m B E r 3 1
B e fo r e r oy a l t i e s
proved
probable
proved plus probable
Bitumen
(MMbbls)
Heavy Oil
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Natural Gas
& CBM
(Bcf)
2010 (1)
2009 (2)
2010 (1)
2009 (2)
2010 (1)
2009 (2)
2010 (1)
2009 (2)
1,154
523
866
479
1,677
1,345
169
97
266
165
104
269
111
49
160
112
53
165
1,390
410
1,800
1,529
436
1,965
(1) refers to 2010 estimates prepared by the IQrEs using McDaniel January 1, 2011 forecast prices and costs.
(2) refers to previously disclosed estimates prepared by the IQrEs using 2009 constant prices and costs.
61 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
r E C O n C I L I At I O n O F P r Ov E D r E s E rv E s
B e fo r e r oy a l t i e s
December 31, 2009 (SEC) (1)
Transition to NI 51-101 Standards (2)
December 31, 2009 (NI 51-101) (3)
Extensions and Improved recovery
Technical revisions
Economic Factors
Dispositions
production
December 31, 2010
Year over year change
Bitumen
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Heavy Oil
(MMbbls)
Natural Gas
& CBM
(Bcf)
866
–
866
270
40
–
–
(22)
1,154
288
33%
165
(1)
164
9
15
–
(5)
(14)
169
4
2%
112
(3)
109
11
1
–
–
(10)
111
(1)
(1%)
1,529
128
1,657
45
60
(18)
(87)
(267)
1,390
(139)
(9%)
(1) refers to previously disclosed estimates prepared by the IQrEs using 2009 constant prices and costs.
(2) The change in reserves disclosed in the transition from SEC to NI 51-101 is a result of (i) the forecast prices and costs used under NI 51-101 were higher than the SEC prescribed constant prices and costs,
restoring previously uneconomic gas reserves, and (ii) the removal of royalty interest reserves from the before royalties reserves totals. See Oil and Gas Information in the Advisory section of this MD&A.
(3) Determined using McDaniel January 1, 2010 forecast prices and costs.
r E C O n C I L I At I O n O F P r O B A B L E r E s E rv E s
B e fo r e r oy a l t i e s
December 31, 2009 (SEC) (1)
Transition to NI 51-101 Standards (2)
December 31, 2009 (NI 51-101) (3)
Extensions and Improved recovery
Technical revisions
Economic Factors
Dispositions
December 31, 2010
Year over year change
Bitumen
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Heavy Oil
(MMbbls)
Natural Gas
& CBM
(Bcf)
479
–
479
132
(88)
–
–
523
44
9%
104
(1)
103
5
(10)
–
(1)
97
(7)
(7%)
53
(2)
51
(1)
(1)
–
–
49
(4)
(8%)
436
52
488
12
(82)
7
(15)
410
(26)
(6%)
(1) refers to previously disclosed estimates prepared by the IQrEs using 2009 constant prices and costs.
(2) The change in reserves disclosed in the transition from SEC to NI 51-101 is a result of (i) the forecast prices and costs used under NI 51-101 were higher than the SEC prescribed constant prices and costs,
restoring previously uneconomic gas reserves, and (ii) the removal of royalty interest reserves from the before royalties reserves totals. See Oil and Gas Information in the Advisory section of this MD&A.
(3) Determined using McDaniel January 1, 2010 forecast prices and costs.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 62
In 2010, proved and proved plus probable bitumen reserves increased by
approximately 33 and 25 percent respectively. This was primarily a result
of receiving regulatory approval to expand the development area at Foster
Creek and from improvements to overall recovery based on operating
performance. Incremental recovery from wedge wells, drilled between
existing producers, and improved recovery resulting from better than
expected drainage from existing wells also contributed to the increase.
In 2010, proved heavy oil reserves increased by approximately two percent
primarily as a result of expanding polymer flood areas and their successful
performance at pelican Lake. probable heavy oil reserves decreased by
approximately seven percent as a result of transfers to proved reserves.
proved plus probable reserves decreased by approximately one percent.
In 2010, proved light and medium oil and NGLs reserves decreased by
approximately one percent, primarily as a result of expanding waterflood and
carbon dioxide flood areas and their successful performance at Weyburn being
offset by current year production. probable light and medium oil and NGLs
reserves decreased by eight percent as a result of transfers to proved reserves.
proved plus probable reserves decreased by approximately three percent.
In 2010, proved natural gas reserves declined by approximately nine percent
as extensions and technical revisions did not offset production and the
divestiture of some of our natural gas assets. probable natural gas reserves
and proved plus probable reserves declined by approximately six percent and
eight percent respectively.
r E s O u r C E s A t D E C E m B E r 3 1
B e fo r e r oy a l t i e s
Economic contingent resources (3)
Low Estimate
Best Estimate
High Estimate
prospective resources (4)
Low Estimate
Best Estimate
High Estimate
Bitumen
(billions of barrels)
2010 (1)
2009 (2)
4.4
6.1
8.0
7.3
12.3
21.7
3.9
5.4
7.3
7.8
12.6
21.4
(1) refers to estimates prepared by McDaniel, using McDaniel January 1, 2011 forecast prices and costs.
(2) refers to previously disclosed estimates prepared by McDaniel, using 2009 constant prices and costs.
(3) See Oil and Gas Information in the Advisory section of this MD&A for definitions of contingent resources, economic contingent resources and low, best and high estimate. There is no certainty that it will
be commercially viable to produce any portion of the contingent resources.
(4) There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
prospective resources are not screened for economic viability.
Best estimate economic contingent resources increased 0.7 billion barrels or
13 percent relative to 2009. This increase is primarily as a result of significant
stratigraphic well drilling converting prospective resources to contingent
resources, and positive technical revisions to volumetric estimates and
recovery factor estimates. Best estimate prospective resources declined
0.3 billion barrels or two percent relative to 2009, primarily as a result of the
reclassification of prospective resources to contingent resources resulting
from stratigraphic drilling.
The contingencies which must be overcome to enable the bitumen economic
contingent resources to be classified as reserves include submission of
regulatory applications with no major issues raised, access to markets, and
intent to proceed by the operator and partners as evidenced by a development
plan with major capital expenditures planned within five years.
Additional reserves and other oil and gas information, including the risks and
uncertainties associated with reserves and resource estimates, is contained in
our AIF, available at www.sedar.com and on our website at www.cenovus.com.
63 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Liquidity and Capital resources
( $ m i lli o n s)
Net cash from (used in)
Operating activities
Investing activities
2010
2009
2008
$
2,594
$
3,039
$
3,225
(1,796)
(2,063)
(2,109)
1,116
(1,227)
1
$
(110)
Net cash provided (used) before Financing activities
Financing activities
Foreign exchange gains (losses) on cash and cash equivalents held in foreign currency
798
(631)
(22)
Increase (decrease) in cash and cash equivalents
$
145
$
976
(977)
(32)
(33)
O P E r AtI n G AC tI v I tI E s
Net cash from operating activities decreased $445 million in 2010 compared
to 2009 mainly because of lower cash flow. Cash flow was $2,415 million
during 2010 (2009–$2,845 million; 2008–$3,115 million). reasons for this
change are discussed in the Cash Flow section of this MD&A. Cash from
operating activities was also impacted by the net change in other assets and
liabilities and the net change in non-cash working capital.
Excluding the impact of risk management assets and liabilities, we had
working capital of $290 million at December 31, 2010 compared to working
capital of $479 million at December 31, 2009. We anticipate that we will
continue to meet the payment terms of our suppliers.
I n v E s tI n G AC tI v I tI E s
Net cash used for investing activities in 2010 decreased to $1,796 million
from $2,063 million in 2009 (2008–$2,109 million). Capital expenditures
increased in 2010 to $2,208 million compared to $2,165 million in 2009
(2008–$2,204 million). Total divestiture proceeds increased in 2010 to
$309 million compared to $222 million in 2009 (2008–$48 million). The
changes to our capital expenditures are discussed under the Net Capital
Investment and Operating Segment sections of this MD&A. Also decreasing
the cash used in investing was the net change in non-cash working capital,
which increased cash and cash equivalents by $99 million in 2010 compared
to a $95 million decrease in 2009 (2008–increase of $96 million).
F I nAn C I n G AC t Iv I t I E s
Cenovus has a committed credit facility and a commercial paper program
that are used to manage our short term cash requirements.
In 2010, we re-negotiated our $2.5 billion credit facility by combining the
two existing tranches into a single tranche and extending the maturity to
November 30, 2014. At December 31, 2010, no amounts were drawn on the
committed credit facility.
In 2010, we filed a Canadian base shelf prospectus for unsecured medium
term notes in the amount of $1.5 billion. The Canadian shelf prospectus
allows for the issue of medium term notes in Canadian dollars or other
foreign currencies from time to time in one or more offerings. The terms of
the notes, including, but not limited to, interest at either fixed or floating
rates and expiry dates, will be determined at the date of issue. At December
31, 2010, no medium term notes have been issued under this Canadian shelf
prospectus. The Canadian shelf prospectus expires in July 2012.
In 2010, we filed a U.S. base shelf prospectus for unsecured notes in the
amount of US$1.5 billion. The U.S. shelf prospectus allows for the issuance of
debt securities in U.S. dollars or other foreign currencies from time to time in
one or more offerings. The terms of the notes, including, but not limited to,
interest at either fixed or floating rates and expiry dates, will be determined
at the date of issue. At December 31, 2010, no notes have been issued under
this U.S. shelf prospectus. The U.S. shelf prospectus expires in August 2012.
In 2010, we declared and paid quarterly dividends of $0.20 per share (2009–
U.S.$0.20 per share in the fourth quarter). Dividend payments for 2010 totaled
$601 million (2009–$159 million). The declaration of dividends is at the sole
discretion of the Board and considered quarterly.
Net cash used in financing activities for 2010 was $631 million (2009–$977
million; 2008–$1,227 million). The 2010 decrease in net cash used in financing
was a result of net financing transactions with Encana in 2009 related to the
Arrangement. In 2009, we completed a private offering of senior unsecured
notes for net proceeds of $3,718 million (U.S.$3,468 million) as well as the
repayment of the $3.7 billion (U.S.$3.5 billion) demand promissory note
to Encana. In 2010, substantially all of these notes were exchanged for
notes registered under the Securities Act of 1933 with the same terms and
conditions as the original issued notes. Our debt was $3,432 million as at
December 31, 2010 and does not require any payments of principal until 2014.
As at December 31, 2010, we are in compliance with all of the terms of our
debt agreements.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 64
F I nAn C I A L m E t r I C s
Debt to Capitalization
Debt to Adjusted EBITDA (times)
Cenovus monitors its capital structure and short-term financing requirements
using, among other things, non-GAAp financial metrics consisting of Debt
to Capitalization and Debt to Adjusted EBITDA. Capitalization is a non-
GAAp measure defined as long-term debt including current portion plus
Shareholders’ Equity. Trailing 12-month Adjusted EBITDA is a non-GAAp
measure defined as adjusted earnings before interest, income taxes, DD&A,
accretion of asset retirement obligations, foreign exchange gains (losses),
gains (losses) on divestiture of assets and other income (loss). Debt is defined
as the current and long-term portions of long-term debt excluding any
amounts with respect to the partnership Contribution payable or receivable.
These metrics are used to steward our overall debt position as measures of
our overall financial strength.
We target a Debt to Capitalization ratio of between 30 to 40 percent and a
Debt to Adjusted EBITDA of between 1.0 to 2.0 times. Additional information
regarding our capital structure can be found in the notes to the Consolidated
Financial Statements.
O u t s tA n D I n G s H A r E D AtA
Cenovus is authorized to issue an unlimited number of common shares, an
unlimited number of first preferred shares and an unlimited number of second
preferred shares. As at December 31, 2010 there were 752.7 million (2009–
751.3 million) common shares outstanding and no preferred shares outstanding.
In 2010, the Board approved a dividend reinvestment plan (“DrIp”), which
permits holders of common shares to automatically reinvest all or any
portion of the cash dividends paid on their common shares in additional
common shares. At the discretion of Cenovus, the additional common shares
may be issued from treasury or purchased on the market. For the year ended
December 31, 2010, common shares were purchased on the market to meet
our DrIp requirements.
The Cenovus Employee Stock Option plan (“ESOp”) permits our Board, from
time to time, to grant to employees of Cenovus and its subsidiaries stock
options to purchase our common shares. Option exercise prices approximate
the market price for the common shares on the date the options were
issued. Options granted under the ESOp are exercisable at 30 percent of
2010
26%
1.2x
2009
28%
1.1x
2008
28%
0.8x
the initial grant after one year, an additional 30 percent of the initial grant
after two years and are fully exercisable after three years and expire five
to seven years after the date granted. Options granted have an associated
tandem share appreciation right (“TSAr”), which gives employees the right to
elect to receive a cash payment equal to the excess of the market price of
our common shares over the exercise price of their option in exchange for
surrendering their option. A portion of the options have an additional vesting
condition which is subject to the Company attaining prescribed performance
relative to key pre-determined measures. The performance-based options
that do not vest when eligible are forfeited. The exercise of an option as a
TSAr for a cash payment does not result in the issuance of any additional
common shares, thus having no dilutive effect.
In accordance with the Arrangement, each Cenovus and Encana employee
holding Encana options prior to the Arrangement received one Cenovus
replacement option and one Encana replacement option for each original
Encana option held. The terms and conditions of the Cenovus replacement
options are similar to the terms and conditions of the original Encana
options, which are also similar to the terms and conditions of Cenovus
options. The original exercise price of the Encana options was apportioned
to the Cenovus and Encana replacement options based on the one-day
weighted average trading price of Cenovus’s common share price relative
to that of Encana’s common share price on the Toronto Stock Exchange on
December 2, 2009.
At December 31, 2010, Cenovus employees held approximately 19.1 million
options, of which 7.7 million were exercisable. At December 31, 2010, Encana
employees held approximately 17.2 million Cenovus replacement options,
of which 10.8 million were exercisable. No further Cenovus replacement
options will be granted to Encana employees. Encana is required to reimburse
Cenovus in respect of cash payments made to Encana employees for Cenovus
replacement options exercised as TSArs. Cenovus is required to reimburse
Encana in respect of cash payments made to Cenovus employees for Encana
replacement options exercised as TSArs. No further Encana replacement
options will be granted to Cenovus employees.
65 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
C O n t r AC t uA L O B L I G At I O n s A n D C O m m I t m E n t s
( $ m i lli o n s)
Long-term Debt (1)
partnership Contribution payable (1)
Asset retirement Obligation
pipeline Transportation
purchases of Goods and Services
product purchases
Operating Leases (2)
Capital Commitments
Other Long-term Commitments
Total payments
product Sales
partnership Contribution receivable (1)
2011
–
343
100
107
157
23
33
91
4
858
50
346
$
$
$
$
2012
–
364
2
93
23
18
87
71
2
660
52
364
$
$
$
$
$
$
$
$
(1) principal component only. See notes to the Consolidated Financial Statements.
(2) Operating leases consist of building leases.
$
2,685
$
Expected payment Date
2013
2014
2015
2016+
–
386
2
167
12
18
88
4
1
678
54
384
$
$
$
$
796
410
2
167
10
18
85
4
1
1,493
56
405
$
$
$
$
–
435
2
166
7
18
78
4
–
710
57
427
581
6,012
953
23
7
1,553
14
1
11,829
63
565
$
$
$
Total
3,481
2,519
6,120
1,653
232
102
1,924
188
9
$
$
$
16,228
332
2,491
Cenovus has entered into various commitments in the normal course
of operations primarily related to debt, future demand charges on firm
transportation agreements (which include amounts for projects awaiting
regulatory approval), building leases, capital commitments and marketing
agreements. In addition, we have commitments related to our risk
management program and an obligation to fund our defined benefit pension
and other post-employment benefit plans. For further information please see
the notes to the Consolidated Financial Statements.
As at December 31, 2010, Cenovus remained a party to long-term, fixed price,
physical contracts for natural gas with a current delivery of approximately
33 MMcf/d, with varying terms and volumes through 2017. The total volume
to be delivered within the terms of these contracts is 73 Bcf of natural gas at
a weighted average price of US$4.54 per Mcf.
In the normal course of business, we also lease office space for personnel
who support field operations and for corporate purposes.
L E G A L P r O C E E D I n G s
We are involved in various legal claims associated with the normal course of
operations and we believe we have made adequate provisions for such claims.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 66
risk management
Our business, prospects, financial condition, results of operations and cash
flows, and in some cases our reputation, are impacted by risks that are
categorized as follows:
• Financial risks including market risk (fluctuations in commodity prices,
foreign exchange rates and interest rates), credit and liquidity risk;
• Operational risks including capital, operating and reserves replacement
risks; and
• Safety, environmental and regulatory risks including regulatory process and
approval risks, stakeholder and partner support for activities and growth
plans and changes to royalty and income tax legislation.
We are committed to identifying and managing these risks in the near-term, as
well as on a strategic and longer term basis at all levels in the organization in
accordance with our Board-approved Market risk Mitigation policy, Enterprise
risk Management policy, Credit policy and risk management programs. Issues
affecting, or with the potential to affect, our assets, operations and/or
reputation, are generally of a strategic nature or are emerging issues that can
be identified early and then managed, but occasionally include unforeseen
issues that arise unexpectedly and must be managed on an urgent basis. We
take a proactive approach to the identification and management of issues
that can affect our assets, operations and/or reputation and have established
consistent and clear policies, procedures, guidelines and responsibilities for
issue identification and management.
Further information regarding the risk factors affecting Cenovus can be found
in the Advisory section of this MD&A and in the risk Factors section of our
AIF for the year ended December 31, 2010.
F I nAn C I A L r I s k s
Financial risk is the risk of loss or lost opportunity resulting from financial
management and market conditions that could have a positive or negative
impact on our business.
We continue to implement our business model which focuses on developing
low-risk and low-cost long-life resource properties. Management monitors
our operational and financial risk strategies to proactively respond to the
changing economic conditions and to eliminate, mitigate or reduce the risk.
Cost containment and reduction strategies are in place to help ensure our
controllable costs are efficiently managed. Counterparty and credit risks are
closely monitored as is our liquidity to ensure access to cost effective credit.
Sufficient cash resources are maintained to fund capital expenditures.
We partially mitigate our exposure to financial risks through the use of
various financial instruments and physical contracts governed by our Market
risk Mitigation policy which contains prescribed hedging protocols and
limits. We have entered into various financial instrument agreements to
mitigate exposure to commodity price risk volatility. The details of these
instruments, including any unrealized gains or losses, as of December 31, 2010,
are disclosed in the notes to the Consolidated Financial Statements and
discussed in this MD&A. The financial instruments used are primarily swaps
which are entered into with major financial institutions, integrated energy
companies or commodities trading institutions and exchanges.
C O M M O d i t y P R i C E R i S k
Commodity price risk is the exposure to fluctuations in future market prices
that results from the sales of various commodities in our operations.
We seek to reduce our exposure to commodity price risk through an
integrated business strategy whereby a portion of operating supplies
and feedstock is provided from internal operations. To further mitigate
commodity price risk, we use derivative instruments in various operational
markets to optimize our supply or production chain. We have partially
mitigated our exposure to the crude oil commodity price risk on our crude
oil sales with fixed price WTI swaps. We have partially mitigated our exposure
to the natural gas commodity price risk on our natural gas sales with fixed
price NYMEX and AECO swaps. We have partially mitigated our exposure
to widening crude oil and natural gas price differentials with fixed price
differential and basis swaps between our production areas and various sales
points. We have mitigated some of our exposure to electricity consumption
costs, with two derivative contracts which expire on January 1, 2018.
C R E d i t R i S k
Credit risk is the potential for loss if a counterparty in a transaction fails to
meet its obligations in accordance with agreed terms.
A substantial portion of our accounts receivable is with customers in the
oil and gas industry. This credit exposure is mitigated through the use of our
Board-approved credit policies governing our credit portfolio and with credit
practices that limit transactions according to counterparties’ credit quality.
All financial derivative agreements are with major financial institutions in
Canada and the United States or with counterparties having investment grade
credit ratings.
l i q U i d i t y R i Sk
Liquidity risk is the risk we will not be able to meet all our financial
obligations as they come due. Liquidity risk also includes the risk of not being
able to liquidate assets in a timely manner at a reasonable price.
We manage our liquidity risk through the active management of cash and
debt by ensuring that we have access to multiple sources of capital including:
cash and cash equivalents, cash from operating activities, undrawn credit
facilities, commercial paper and availability under our shelf prospectuses.
At December 31, 2010, no amounts were drawn on our committed credit
facility. In addition, we had $1.5 billion in unused capacity under our Canadian
shelf prospectus and US$1.5 billion in unused capacity under our U.S. shelf
prospectus, the availability of which are dependent on market conditions.
F O R E i g n E xC h a n g E R i S k
Foreign exchange risk is the exposure to fluctuations in foreign currency
exchange rates in our operations. As our commodity sales are generally priced
in U.S. dollars and our capital expenditures and expenses are paid in both U.S.
and Canadian dollars, fluctuations in the exchange rate between the U.S. and
Canadian dollar can have a significant effect on our financial results which are
reported in Canadian dollars.
67 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
We reduce our exposure to foreign exchange risk through an integrated
business strategy with a mix of U.S. and Canadian operations that creates
a partial hedge to foreign exchange exposure. To further mitigate foreign
exchange risk, we may enter into foreign exchange contracts or hedge our
commodity exposures in Canadian dollars.
We also have the flexibility to maintain a mix of both U.S. dollar and Canadian
dollar debt, which helps to offset the exposure to the fluctuations in the
U.S./Canadian dollar exchange rate. In addition to direct issuance of U.S. dollar
denominated debt, we may enter into cross currency swaps on a portion of
our debt as a means of managing the U.S./Canadian dollar debt mix.
We utilize a peer review process to ensure that capital projects are
appropriately risked and that knowledge is shared across our company. peer
reviews are undertaken primarily for early stage properties, although they
may occur for any type of project.
When making operating and investing decisions, our business model allows
flexibility in capital allocation to optimize investments focused on strategic
fit, project returns, long-term value creation, and risk mitigation. We also
mitigate operational risks through a number of other policies, systems and
processes as well as by maintaining a comprehensive insurance program in
respect of our assets and operations.
in tE R E S t R atE R i Sk
s A F E t Y, E n v I r O n m E n tA L A n D r E G u L At O rY r I s k s
Interest rate risk is the impact of changing interest rates on earnings, cash
flows and valuations. Although all of our debt portfolio was fixed rate debt at
December 31, 2010, we have the flexibility to partially mitigate our exposure
to interest rate changes by maintaining a mix of both fixed and floating rate
debt through the use of our commercial paper program and credit facilities.
We may also enter into interest rate swap transactions from time to time as
an additional means of managing the fixed/floating rate debt portfolio mix.
O P E r At I O n A L r I s k s
Operational risk is the risk of loss or lost opportunity resulting from operating
and capital activities that, by their nature, could have an impact on our ability
to achieve our objectives.
Our ability to operate, generate cash flows, complete projects and value reserves
is dependent on financial risks, including commodity prices mentioned above,
continued market demand for our products and other risk factors outside of
our control, which include: general business and market conditions; economic
recessions and financial market turmoil; the ability to secure and maintain cost
effective financing for our commitments; the ability to obtain necessary approvals;
environmental and regulatory matters; unexpected cost increases; royalties;
taxes; the availability of drilling and other equipment; the ability to access lands;
weather; the availability of processing capacity; the availability and proximity of
pipeline capacity; the availability of diluents to transport crude oil; technology
failures; accidents; the availability of skilled labour; and reservoir quality.
If we fail to acquire, develop or find additional crude oil and natural gas
reserves, our reserves and production will decline materially from their
current levels and, therefore, our cash flows are highly dependent upon
successfully producing current reserves and acquiring, discovering or
developing additional reserves.
To mitigate these risks, as part of the capital approval process, we evaluate
projects on a fully risked basis, including geological risk and engineering
risk. In addition, our asset teams undertake a process called Lookback and
Learning. In this process, each asset team undertakes a thorough review of
its previous capital program to identify key learnings, which often include
operational issues that positively and negatively impacted the project’s
results. Mitigation plans are developed for the operational issues that had
a negative impact on results. These mitigation plans are then incorporated
into the current year plan for the project. On an annual basis, these Lookback
and Learning results are analyzed in relation to our capital program with the
results and identified learnings shared across our company.
We are engaged in the relatively high risk activities of crude oil and natural
gas development and production and refining. We are committed to
safety in our operations and with high regard for the environment and
stakeholders. These risks are managed by executing policies and standards
that are designed to comply with or exceed government regulations and
industry standards. In addition, we maintain a system, in respect of our assets
and operations, that identifies, assesses and controls safety, security and
environmental risk and requires regular reporting to both senior management
and our Board. The Safety, Environment and responsibility Committee
of our Board reviews and recommends policies pertaining to corporate
responsibility, including the environment, for approval by our Board and
oversees compliance with government laws and regulations. Monitoring and
reporting programs for environmental, health and safety performance in
day-to-day operations, as well as inspections and assessments, are designed
to provide assurance that environmental and regulatory standards are met.
Contingency plans are in place for a timely response to an environmental
event and remediation/reclamation strategies are utilized to restore the
environment. In addition, security risks are managed through a security
program designed to protect our personnel and assets.
We have an Investigations Committee whose mandate is to address potential
violations of policies and practices and an Integrity Helpline that can be used to
raise any concerns regarding operations, accounting or internal control matters.
Our operations are subject to regulation and intervention by governments
that can affect or prohibit the drilling, completion and tie-in of wells,
production, the construction or expansion of facilities and the operation
and abandonment of fields. Contract rights can be cancelled or expropriated.
Changes to government regulation could impact our existing and planned
projects as well as impose a cost of compliance.
regulatory and legal risks are identified by our operating and corporate
groups, and our compliance with the required laws and regulations is
monitored by our legal group in respect of our assets and operations. Our
legal and environmental policy groups stay abreast of new developments
and changes in laws and regulations to ensure that we continue to comply
with prescribed laws and regulations. Of note in this regard, our approach
to changes in regulations relating to climate change, royalty and regulatory
frameworks is discussed below. To partially mitigate resource access risks,
keep abreast of regulatory developments and be a responsible operator, we
maintain relationships with key stakeholders and conduct other mitigation
initiatives mentioned herein.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 68
E n v i R O n M E n ta l R E g U l at i O n a n d R i S k
Environmental regulation impacts many aspects of our business. regulatory
regimes apply to all companies active in the energy industry. We are required
to obtain regulatory approvals, licenses and permits in order to operate
and we must comply with standards and requirements for the exploration,
development and production of crude oil and natural gas and the refining,
distribution and marketing of petroleum products. regulatory assessment,
review and approval are generally required before initiating, advancing or
changing operations projects. Further information regarding the status of
each project can be found in the Operating Segments section of this MD&A.
tracking, attention to fuel consumption and a focus on minimizing our steam
to oil ratio help to support and drive our focus on cost reduction.
(2) respond to price Signals
As regulatory regimes for GHGs develop in the jurisdictions where we
work, inevitably price signals begin to emerge. We have initiated an
Energy Efficiency Initiative in an effort to improve the energy efficiency
of our operations. The price of potential carbon reductions plays a role
in the economics of the projects that are implemented. In response to
the anticipated price of carbon reduction, we are also attempting, where
appropriate, to realize associated value of our reduction projects.
C l i M at E C h a n g E
(3) Anticipate Future Carbon Constrained Scenarios
Various federal, provincial and state governments have announced intentions
to regulate greenhouse gas (“GHG”) emissions and other air pollutants and a
number of legislative and regulatory measures to address GHG emissions are in
various phases of review, discussion or implementation in the U.S. and Canada.
Adverse impacts to our business if comprehensive GHG regulation is enacted
in any jurisdiction in which we operate may include, among other things,
increased compliance costs, permitting delays, substantial costs to generate or
purchase emission credits or allowances which may add costs to the products
we produce and reduce demand for crude oil and certain refined products.
Beyond existing legal requirements, the extent and magnitude of any adverse
impacts of any of these additional programs cannot be reliably or accurately
estimated at this time because specific legislative and regulatory requirements
have not been finalized and uncertainty exists with respect to the additional
measures being considered and the time frames for compliance.
We intend to continue our activity to use scenario planning to anticipate
future impacts, reduce our emissions intensity and improve our energy
efficiency. We will also continue to work with governments to develop an
approach to deal with climate change issues that protects the industry’s
competitiveness, limits the cost and administrative burden of compliance and
supports continued investment in the sector.
The Government of Alberta has set targets for GHG emissions reductions.
regulations require facilities that emit more than 100,000 tonnes of GHG
emissions per year to reduce their emissions intensity by 12 percent from a
regulated baseline. To comply, companies can make operating improvements,
purchase carbon offsets (or emission performance credits) or make a $15 per
tonne contribution to an Alberta Climate Change and Emissions Management
Fund. Cenovus currently has three facilities subject to this regulation. For the
2010 compliance year, we do not anticipate material costs in this regard.
Our efforts with respect to emissions management are founded in our industry
leadership in carbon dioxide sequestration, a focus on energy efficiency and
the development of technology to reduce GHG emissions. In particular, our
low steam to oil ratios at Foster Creek and Christina Lake translates directly
into lower emissions intensity. Given the uncertainty in North American carbon
legislation, our strategy for addressing the implications of emerging carbon
regulations is proactive and is composed of three principal elements:
(1) Manage Existing Costs
When regulations are implemented, a cost is placed on our emissions (or a
portion thereof) and while these are not material at this stage, they are being
actively managed to ensure compliance. Factors such as effective emissions
We continue to work with governments, academics and industry leaders to
develop and respond to emerging GHG regulations. By continuing to stay
engaged in the debate on the most appropriate means to regulate these
emissions, we gain useful knowledge that allows us to explore different
strategies for managing our emissions and costs. These scenarios assist with our
long range planning and our analyses on the implications of regulatory trends.
We incorporate the potential costs of carbon into future planning.
Management and the Board review the impact of a variety of carbon
constrained scenarios on our strategy, with a current price range from $15 to
$65 per tonne of emissions applied to a range of emissions coverage levels.
A major benefit of applying a range of carbon prices at the strategic level is
that it can provide direct guidance to the capital allocation process. We also
examine the impact of carbon regulation on our major projects. Although
uncertainty remains regarding potential future emissions regulation, our
plan is to continue to assess and evaluate the cost of carbon relative to our
investments across a range of scenarios.
We recognize that there is a cost associated with carbon emissions. We
believe that GHG regulations and the cost of carbon at various price levels
have been adequately taken into consideration as part of our business
planning and scenarios analysis. We believe that our development strategy,
use of technology and focus on continuous improvement is an effective way
to develop the resource, generate shareholder returns and coordinate overall
environmental objectives with respect to carbon, air emissions, water and
land. We are committed to transparency with our stakeholders and will keep
them apprised of how these issues affect our operations.
A L B E r tA’ s r OYA L t Y F r A m E WO r k
In 2010, the Government of Alberta outlined changes to the royalty
structure in the province. The updates to conventional crude oil and natural
gas royalty structure released in the first quarter of 2010 included:
• A five percent maximum royalty rate on new gas and conventional oil wells
for a period of 12 months or 0.5 billion cubic feet equivalent for gas wells
or 50,000 barrels of oil equivalent for oil wells, whichever comes first. The
five percent royalty rate was originally created with the New Well Incentive
under the Energy Incentive program that was released on March 3, 2009
and was set to expire on March 31, 2011, but is now permanently in place;
• The maximum royalty rate for conventional oil will decrease to 40 percent
from 50 percent and the maximum natural gas royalty rate will decrease to
36 percent from 50 percent; and
69 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
• Effective January 1, 2011 no additional wells will be allowed under the
Transitional royalty program (“Trp”) that went into effect on January 1,
2009. The Trp allows for a one time option of selecting transitional royalty
rates on new natural gas or conventional oil wells drilled between 1,000
to 3,500 metres in depth. Any wells that are elected under the Trp can
continue to use this program until December 31, 2013.
Updates released in the second quarter of 2010 were primarily focused
on supporting deep basin gas drilling and improving the economics of
unconventional gas plays, as well as horizontal oil and gas drilling. These
updates included:
• A maximum royalty rate of five percent for all products produced
from horizontal oil or horizontal non-oil sands wells, with volume and
production month limits set according to the depth of the well. Horizontal
oil and non-oil sands wells are defined by the ErCB;
• Wells defined as horizontal natural gas wells by the ErCB will have a
maximum five percent royalty rate on all production for a period of 18
producing months or 500 MMcf of gas equivalent production;
• CBM wells that produce exclusively from areas defined by the ErCB as
coal will have a maximum royalty rate of five percent on all products
produced in the first 36 months with a production limit of 750 MMcf of gas
equivalent; and
• The Natural Gas Deep Drilling program was made permanent and was
modified and simplified. Modifications include the reduction of the
minimum well depth to 2,000 metres; elimination of well target, spacing
and pool boundary restrictions; all lateral wells qualify for credits;
increased credits between 3,500 and 5,000 metres; and removal of
maximum well depth.
Also included as part of the royalty structure changes released in the second
quarter were updates to the royalty curves for conventional oil and natural
gas. The effective date of the new curves is January 1, 2011.
For Cenovus, the main impact of these royalty changes is expected to be a
positive improvement to the economics of our oil drilling program for certain
properties in our Conventional operating segment and any future shale oil
developments in Alberta.
A L B E r tA’ s r E G u L At O rY F r A m E WO r k
As part of the Government of Alberta’s competitiveness review, a
comprehensive review of Alberta’s regulatory system called the regulatory
Enhancement project (the “project”) was initiated in March 2010. The
project’s goal is to create an effective regulatory system that will contribute
to Alberta’s overall competitiveness while protecting the environment,
ensuring public safety and conservation of resources. The project involved
engagement with a broad range of stakeholders, including industry, and led to
a recommendation to the Minister of Energy for adoption of a coordinated
policy framework and an integrated regulatory system for the upstream
oil and gas sector. The Government of Alberta has accepted the projects
team’s recommendations and is expected to begin implementing those
recommendations in the first half of 2011.
Alberta’s Land-use Framework, which is to be implemented under the
Alberta Land Stewardship Act (“ALSA”), sets out the Government of Alberta’s
approach to managing Alberta’s land and natural resources to achieve
long-term economic, environmental and social goals. ALSA contemplates
the amendment or extinguishment of previously issued consents such as
regulatory permits, licenses, approvals and authorizations in order to achieve
or maintain an objective or policy resulting from the implementation
of a regional plan. The Government of Alberta is expected to develop a
regional plan for each of seven regions in the province and has identified the
Lower Athabasca regional plan (“LArp”) as a priority. The LArp is intended
to identify and set resource and environmental management outcomes
for air, land, water and biodiversity, and guide future resource decisions
while considering social and economic impacts. In August 2010, the Lower
Athabasca regional Advisory Council (“rAC”) provided its vision document
to the Government of Alberta regarding the LArp. Cenovus is actively
participating in the feedback process as a stakeholder with significant
activities in the region and will continue to monitor developments going
forward. The Government of Alberta is expected to respond to the rAC
advice with its own LArp recommendations. It is possible that the rAC vision,
if adopted in its current form by the Government of Alberta, may negatively
impact Cenovus’s access to certain resource properties or limit the pace of
development due to environmental limits and thresholds.
t r A n s PA r E n C Y A n D C O r P O r At E r E s P O n s I B I L I t Y
We are committed to operating in a responsible manner and to integrating our
corporate responsibility principles into the way we conduct our business. We
recognize the importance of reporting to stakeholders in a transparent and
accountable manner. We disclose not only the information we are required to
disclose by legislation or regulatory authorities, but also information that more
broadly describes our activities, policies, opportunities and risks.
Our Corporate responsibility (“Cr”) policy has been updated to ensure
that it continues to drive our commitments, strategy and reporting, and
also enables alignment with our business objectives and processes. Our
future Cr reporting activities will be guided by this policy and will focus on
improving performance by continuing to track, measure and monitor our Cr
performance indicators. This policy was released on December 1, 2010 and is
available on our website at www.cenovus.com.
In 2010, we released our “Corporate responsibility performance Highlights”
fact sheet and launched the Cr section of our website. The two-page fact
sheet introduced Cenovus to our stakeholders and provided a snapshot of
our 2009 Cr performance. It was distributed to all of our staff, including
contractors and staff in the field and to over 1,000 of our external contacts.
We also created a more detailed “Corporate responsibility 2009 performance
Measures report” to complement the fact sheet. The performance Measures
report organizes all 2009 Cr metrics into one document and is available on
our website at www.cenovus.com.
As our Cr reporting process matures, indicators will be developed that
better reflect Cenovus’s operations and challenges. These indicators will be
integrated into our Cr reporting and will expand our online presence through
our website.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 70
Accounting Policies and Estimates
Management is required to make judgments, assumptions and estimates
in the application of GAAp that have a significant impact on our financial
results. Actual results may differ from those estimates, and those differences
may be material. The basis of presentation and our significant accounting
policies can be found in the notes to the Consolidated Financial Statements.
C r I t I C A L A C C O u n t I n G P O L I C I E s A n D E s t I m At E s
The following discussion outlines the accounting policies and practices involving
the use of estimates that are critical to understanding our financial results.
B a S i S O F P R E S E n tat i O n
Our results for the year ended December 31, 2010 and the one month period
from December 1 to December 31, 2009 represent our operations, cash flows
and financial position as a stand-alone entity.
Our results for the periods prior to the Arrangement, being January 1
to November 30, 2009 and January 1 to December 31, 2008, have been
prepared on a “carve-out” accounting basis, whereby the results have been
derived from the accounting records of Encana using the historical results
of operations and historical basis of assets and liabilities of the businesses
transferred to Cenovus. The historical consolidated financial statements
include allocations of certain Encana expenses, assets and liabilities. In the
opinion of management, the consolidated and the historical carve-out
consolidated financial statements reflect all adjustments necessary for a fair
statement of the financial position and the results of operations and cash
flows in accordance with GAAp.
Management believes that the assumptions underlying the historical
consolidated financial statements are reasonable. However, as we operated as
part of Encana and were not a stand-alone company prior to November 30,
2009, the historical consolidated financial statements included herein may
not necessarily reflect our results of operations, financial position and cash
flows had we been a stand-alone company during the periods presented.
O i l a n d g a S R E S E Rv E S
All of our oil and gas reserves are evaluated and reported to Cenovus by the
IQrEs. The estimation of reserves is a subjective process. Forecasts are based on
engineering data, projected future rates of production, estimated commodity
price forecasts and the timing of future expenditures, all of which are subject
to numerous uncertainties and various interpretations. reserves estimates can
be revised upward or downward based on the results of future drilling, testing,
production levels and economics of recovery based on cash flow forecasts.
These revisions can have a significant impact on our future earnings because
they will directly impact our DD&A rates, asset impairment calculations,
accounting for business combinations and asset retirement obligations.
P R O P E R t y, P l a n t a n d E q U i P M E n t – d d & a
Crude oil and natural gas properties are accounted for in accordance with
the Canadian Institute of Chartered Accountants (“CICA”) guideline on full
cost accounting in the oil and gas industry. Under this method, all costs,
including internal costs and asset retirement costs, directly associated with
the acquisition of, exploration for, and the development of crude oil and
natural gas reserves, are capitalized on a country-by-country cost centre basis
and costs associated with production are expensed. The capitalized costs, plus
estimated future development costs, are depreciated, depleted and amortized
using the unit-of-production method based on estimated proved reserves.
reserves estimates can have a significant impact on earnings, as they are a key
component in the calculation of DD&A. A downward revision in our estimate
of reserve quantities could result in a higher DD&A charge to earnings.
a S S E t i M Pa iR M E n t S
Under GAAp, the carrying amount of crude oil and natural gas properties in
each cost centre may not exceed their recoverable amount. The recoverable
amount is calculated as the total undiscounted cash flow using proved
reserves and estimated future prices and costs. If the carrying amount of a
cost centre exceeds its recoverable amount, the impairment loss is limited
to an amount by which the carrying amount exceeds the sum of:
i) the fair value of proved and probable reserves; and
ii) the costs of unproved properties that have been subject to a separate
impairment test.
We also perform an annual impairment test on goodwill, whereby the fair
value of each reporting unit is determined and compared to the book value
of the reporting unit. A reporting unit has all assets, including goodwill, and
liabilities allocated to the country cost centre level.
For the above impairment tests, fair value is calculated as the cash flows from
oil and gas properties using proved and probable reserves and estimated
future prices and costs, discounted at a risk-free interest rate. In order to
estimate future cash flows, we are required to make a number of assumptions
and estimates, including quantities of reserves, future commodity prices as
well as development and operating costs. Changes in any of the assumptions,
such as a downward revision in reserves, a decrease in commodity prices or
an increase in costs, could result in an impairment of an asset’s carrying value.
An impairment loss is recognized on refining property, plant and equipment
when the carrying amount is not recoverable and exceeds its fair value. The
carrying amount is not recoverable if the carrying amount exceeds the sum of
the undiscounted cash flows from expected use and eventual disposition. If
the carrying amount is not recoverable, an impairment loss is measured as the
amount by which the carrying amount exceeds the fair value.
71 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
B U S i n E S S C O M B i n at i O n S
The purchase price of business combinations and asset acquisitions is
allocated to the underlying acquired assets and liabilities based on their
estimated fair value at the time of acquisition. The determination of fair value
requires the use of assumptions and estimates regarding future events. The
allocation process is inherently subjective and impacts the amounts assigned
to individually identifiable assets and liabilities. As a result, the purchase price
allocation will have a direct impact on our future net earnings, largely due to
the impact on the calculation of DD&A rates or asset impairment tests.
a S S E t R E t i R E M E n t O B l i g at i O n S
We are required to recognize an asset retirement obligation (“ArO”) liability
for the future abandonment and reclamation costs associated with our
property, plant and equipment. ArO is only recognized to the extent there
is a legal obligation associated with the retirement of a tangible long-lived
asset that we are required to settle as a result of an existing or enacted law.
Our calculation of ArO is based on estimated costs, taking into account
the anticipated method and extent of restoration consistent with legal and
regulatory requirements, contracts and current technologies. There are many
assumptions used in the estimate of the ArO liability which can be subject
to change based on experience. These assumptions include: the estimated
cost of reclaiming producing well sites, crude oil and natural gas processing
plants and refining facilities; inflation rates; credit-adjusted risk free rates;
and the timing of retirement of assets. At the end of each year, we review
our assumptions and estimates and any changes to the ArO liability are
discounted to present value using a credit-adjusted risk-free discount rate.
C O M P E n S at i O n P l a n S
We have obligations for payments to our employees related to our stock
option and incentive plans. The obligations provide for a range of payouts
based on key predetermined performance measures and the cost of these
plans is expensed based on expected payouts. The amounts to be paid, if any,
may vary from the current estimate.
We also have obligations for payments to our employees related to stock
option plans of Encana. The financial liability for these obligations is accrued
using the fair value method, and therefore fluctuations in the fair value will
affect the accrued compensation expense that is recognized. The fair value
of the obligation fluctuates, as it is based on assumptions for the risk-free
discount rate, dividend yield, as well as the volatility of Encana’s share price.
R i S k M a n ag E M E n t aC t i v i t i E S
We use various derivative financial instruments to manage our commodity
price, foreign currency and interest rate exposures. These financial instruments
are entered into solely for hedging purposes and are not used for speculative
purposes. The estimated fair value of derivative financial instruments is
determined using appropriate valuation models and methodologies. Fair values
determined using valuation models require the use of assumptions concerning
the amount and timing of future cash flows and discount rates. In determining
these assumptions, we rely primarily on external readily observable market
inputs including quoted commodity prices and volatility, interest rate yield
curves, and foreign exchange rates. The resulting fair value estimates may not
necessarily be indicative of the amounts that may be realized or settled in a
current market transaction and these differences may be material.
i n C O M E t a x E S
We follow the liability method of accounting for income taxes. Under this
method, future income tax assets and liabilities are recognized based on the
estimated tax effects of temporary differences between the carrying value
of assets and liabilities in the consolidated financial statements and their
respective tax bases, using income tax rates substantively enacted as of the
consolidated balance sheet date. Accounting for income taxes is a complex
process that requires the interpretation of changing laws and regulations, for
example changing income tax rates, and making certain judgments with respect
to the application of tax law, estimating the timing of temporary difference
reversals, and estimating the realizability of tax assets. These interpretations
and judgments have a significant impact on our provision for current and future
income tax, and will have a direct impact on our future net earnings.
n E W A C C O u n t I n G s tA n DA r D s A D O P t E D
On January 1, 2010, Cenovus early adopted CICA Handbook Section 1582,
“Business Combinations”, which replaces CICA Handbook Section 1581 of
the same name. The new standard requires assets and liabilities acquired
in a business combination, contingent consideration and certain acquired
contingencies to be measured at their fair values as of the date of acquisition.
In addition, acquisition-related and restructuring costs are to be recognized
separately from the business combination and included in the Statement
of Earnings. This accounting policy was applied to the November 1, 2010
purchase of the marine terminal facilities.
In conjunction with the early adoption of CICA Handbook Section 1582, the
Company was also required to early adopt CICA Handbook Sections 1601,
“Consolidated Financial Statements” and 1602, “Non-controlling Interests”
effective January 1, 2010. These sections replace the former consolidated
financial statement standard, CICA Handbook Section 1600, “Consolidated
Financial Statements”. Section 1601 establishes the requirements for the
preparation of the consolidated financial statements and Section 1602
establishes the accounting for a non-controlling interest in a subsidiary in
consolidated financial statements subsequent to a business combination. Section
1602 requires a non-controlling interest to be classified as a separate component
of equity. In addition, net earnings, and components of other comprehensive
income are attributed to both the parent and non-controlling interest. The early
adoption of these standards did not have a material impact on the Company’s
Consolidated Financial Statements for the year ended December 31, 2010.
These standards are converged with International Financial reporting
Standards (“IFrS”).
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 72
r E C E n t AC C O u n t I n G P r O n O u n C E m E n t s
U P S t R E a M P P & E
There are no pending GAAp accounting pronouncements, other than the
requirement to adopt IFrS in 2011, as discussed below.
I n t E r nA t I O nA L F I nAn C I A L r E P O r t I n G s tAn DAr D s
We are required to report our results in accordance with IFrS beginning with
the three month period ending March 31, 2011. We have a detailed changeover
plan, which includes the preparation of required comparative information
for 2010. We continue to be on schedule with our plan, and expect that
the adoption of IFrS will not have a significant impact or influence on our
business, operations or strategies.
The information below summarizes our accounting policies and opening
balance sheet information, which were disclosed in our MD&A for previous
periods. It also includes additional information on the estimated IFrS impacts
on our financial results for the year ended December 31, 2010.
Our IFrS financial results have not yet been finalized because:
• The results remain subject to further review by management;
• We are continuing to monitor any new or amended IFrS issued by the
International Accounting Standards Board that could affect our choice of
accounting policies;
• Our IFrS financial statements for the year ending December 31, 2011 must
use the standards that are in effect on December 31, 2011, and therefore our
IFrS accounting policies will only be finalized when our first annual IFrS
financial statements are prepared for the year ending December 31, 2011; and
• The results are unaudited and are subject to additional audit work by our
external auditors.
S i g n i F i C a n t i M P aC t S O F i F R S
The following areas are the most significantly affected by the adoption of IFrS:
• Upstream property, plant and Equipment (“pp&E”), including:
– Exploration and Evaluation costs
– Asset retirement obligation
– Transition on date of adoption of IFrS
– DD&A
– Gains and losses on divestitures
• refining Assets
• Impairment testing
• Stock-based compensation
• Income taxes
Exploration and Evaluation costs
During the exploration and evaluation (“E&E”) phase, we capitalized costs
incurred for these projects under GAAp. While this capitalization policy has
not changed under IFrS, these costs will be reported separately as E&E assets,
rather than being included in pp&E.
Asset retirement Obligation
Under GAAp, the discount rates used to estimate the ArO liability were not
updated to current market discount rates, while under IFrS, the discount rate
is updated each reporting period. This difference in accounting policy did
not have a significant impact on either our opening balance sheet or our net
earnings for the year ended December 31, 2010. However, our ArO liability
as of December 31, 2010 was higher under IFrS as a result of changes to the
discount rate used to estimate the liability. The impact is expected to be less
than $200 million.
Transition adjustments on date of adoption of IFrS – January 1, 2010
Under GAAp, we follow full cost accounting, while IFrS has no equivalent
treatment. IFrS 1 (“First-time Adoption of IFrS”) permits full cost accounting
companies to allocate their existing upstream pp&E net book value (full
cost pool) to the unit of account level upon transition to IFrS using reserve
information. Using this exemption, we reclassified the cost of our unproved
properties from Upstream pp&E to the new E&E asset category, and allocated
the remainder of our Upstream full cost pool to our IFrS areas based on the
relative fair value of each area. Fair value was calculated using the estimated
future net cash flows from proved reserves, discounted at 10 percent, since
this was considered to be an appropriate estimate of the relative fair value of
each of our IFrS areas. This approach was also consistent with the allocation
method which was required to be used in the formation of Cenovus. The
allocation process did not affect the net book value of our Upstream pp&E as
no IFrS impairments were recognized.
DD&A
Under GAAp, we calculated our DD&A rate at the country cost centre level.
Under IFrS, this rate is calculated at a lower unit of account level, which
resulted in our Upstream DD&A for the year ended December 31, 2010
increasing by less than $150 million. The increase in DD&A is primarily due
to separating the long life reserves associated with the Foster Creek and
Christina Lake properties from the rest of the full cost pool.
Gains and losses on divestitures
Full cost accounting under GAAp required that gains or losses on divestitures
of pp&E only be recognized when the disposal would affect our DD&A rate
by 20 percent or more. Under IFrS, we are required to recognize all gains and
losses on upstream property divestitures. For the year ended December 31,
2010, we recognized gains on divestiture of oil and gas properties of about
$125 million. Under GAAp, these gains were credited to the full cost pool, and
would have resulted in a lower GAAp DD&A rate in future years compared to
our IFrS DD&A rates.
73 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
R E F i n i n g a S S E t S
S U M M a Ry O F i F R S i M PaC t S t O d E C E M B E R 3 1 , 2 0 1 0
In our IFrS opening balance sheet, we elected to re-measure the carrying
value of our refineries to their fair value, which permanently reduced their
carrying value by approximately $2.6 billion ($1.6 billion, after-tax). In addition,
having revalued the refineries to their fair values, it was also determined
that the refining deferred asset, which had a carrying value of $121 million
at January 1, 2010, was fully impaired under IFrS. The impairment loss on a
refining process unit recognized under GAAp was reduced under IFrS due
to the January 1, 2010 fair value election. The impact of these three IFrS
adjustments was a decrease in our refining and Marketing DD&A of less than
$150 million for the year ended December 31, 2010.
i M Pa iR M E n t t E S t i n g
In the first step for all of our GAAp impairment tests (Upstream, refining and
Goodwill), future cash flows are not discounted. Under IFrS, the future cash
flows are discounted. In addition, for Upstream pp&E, impairment testing was
performed at the country cost centre level, while under IFrS, it is performed
at the lower cash-generating unit level. There was no impact on our Upstream
pp&E, refining pp&E or goodwill with this change in accounting policy.
S tO C k- B a S Ed C O M P En S at iO n
Under GAAp, obligations for cash payments under stock-based compensation
plans were accrued using the intrinsic method, while under IFrS these
obligations are accounted for using the fair value method. While the carrying
value in each reporting period will be different under IFrS compared to
GAAp, the cumulative expense recognized over the life of the instrument
under both methods will not be different. This difference in policy did not
have a significant impact on either our IFrS opening balance sheet or our net
earnings for the year ended December 31, 2010.
i n C O M E t a x E S
The carrying amounts of our tax balances have been directly impacted
by the tax effects resulting from changes in our accounting policies. The
future income tax liability on our IFrS opening balance sheet was reduced
by approximately $1 billion, primarily due to the fair value election on our
refineries. For the year ended December 31, 2010, our income tax expense
increased primarily related to the tax effects on the recognition of gains on
our pp&E divestitures.
The net effect of the significant adjustments above is an increase to our net
earnings mainly due to the gain on divestiture of oil and gas properties. All
of the other IFrS adjustments are not significant. In total, we estimate an
increase to our net earnings under IFrS for the year ended December 31, 2010
of less than $120 million.
The most significant impacts on our December 31, 2010 balance sheet
are as follows:
• Decrease in pp&E of approximately $2.2 billion;
• re-classification of approximately $0.7 billion of Upstream pp&E to E&E assets;
• Decrease in Other assets of approximately $0.1 billion;
• Increase in Asset retirement Obligation of approximately $0.2 billion;
• Decrease in Future Income Taxes of approximately $0.9 billion; and
• Decrease in Shareholders’ Equity of approximately $1.6 billion.
These balance sheet changes increased our Debt to Capitalization ratio at
December 31, 2010, from 26 percent to 29 percent, which is below our target
range of 30 percent to 40 percent.
In terms of our cash flow statement for the year ended December 31, 2010,
the IFrS adjustments did not have a significant impact on cash from operating
activities, cash used in investing activities, or cash from financing activities.
Furthermore, the IFrS adjustments did not have a significant impact on cash
flow, which is our non-GAAp measure defined earlier in this MD&A.
i n t E R n a l C O n t R O l S Ov E R F i n a n C i a l R E P O R t i n g & d i S C lO S U R E
C O n t R O l S a n d P R O C E d U R E S
During the fourth quarter of 2010, we have updated our internal controls
documentation related to external financial reporting processes, including
disclosure controls and procedures. We do not expect that the adoption of
IFrS will have a significant impact on any of our internal control processes.
F i n a n C i a l R E P O R t i n g E x P E R t i S E
In terms of financial literacy, we held additional internal IFrS education
sessions in the fourth quarter of 2010. These education sessions will continue
during 2011 across all of our finance teams to ensure that there is a strong
level of knowledge of IFrS throughout the organization. We will also
continue to educate our external stakeholders, primarily by disclosing and
explaining the significant adjustments from GAAp to IFrS.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 74
Outlook
Our long term objective is to focus on building net asset value and generating
an attractive total shareholder return through the following strategies:
• Material growth in oil sands production, primarily through expansions at
our Foster Creek and Christina Lake properties, and heavy oil production
at pelican Lake. We also have an extensive inventory of new resource play
assets such as Narrows Lake, Grand rapids and Telephone Lake, and have a
100 percent working interest in many of these assets;
• Continue the development of our resources in multiple phases using a low
cost manufacturing-like approach;
• Leadership in low cost oil sands development enabled by technology,
innovation and continued respect for the health and safety of our
employees, emphasis on industry leading environmental performance and
meaningful dialogue with our stakeholders;
• To primarily fund growth internally through free cash flow generation
mainly from our established conventional crude oil and natural gas assets
along with sufficient capacity on our debt facilities for additional cash
requirements, as well as proceeds generated from our ongoing portfolio
management strategy to divest of non-core oil and gas assets;
• Maintaining a lower risk profile through natural gas and refining integration
as well as a consistent hedging strategy; and
• Maintaining a meaningful dividend.
We expect that global oil demand will continue to increase which should
allow for continued strength in WTI prices. We are expecting the light-heavy
differential, represented by WCS crude oil prices, to remain close to historical
trends due to pipeline disruptions and Canadian heavy crude supply growing
in advance of new coking capacity and pipeline access to the Gulf of Mexico.
Once the new refinery and pipeline capacity is in place there should be
strengthening in WCS. If the pipeline disruptions and apportionment that
occurred in the second half of 2010 persist, we expect widened light-heavy
oil differentials to continue in 2011, which should benefit our refining financial
results. Offsetting this is a relatively weak price outlook for natural gas and
refining margins although refining margins will benefit from any near term
congestion in inland markets. The key challenges that need to be effectively
managed to enable our growth are commodity price volatility, timely
regulatory and partner approvals, environmental regulations and competitive
pressures within our industry. Additional detail regarding the impact of these
factors on our 2010 results is discussed in the risk Management section of
this MD&A and in our AIF for the year ended December 31, 2010.
We expect our 2011 capital investment program to be primarily internally
funded through cash flow with sufficient capacity on our debt facilities for
additional cash requirements. We also plan to divest of certain non-core
assets in 2011 for proceeds of $300 to $500 million. Our conventional crude
oil and natural gas assets in Alberta and Saskatchewan are key to providing
free cash flow to enable oil sands growth. Our 10 year business plan outlines
how Cenovus expects to reach net oil sands production of 300,000 bbls/d
by the end of 2019. We are planning continued expansions at Foster Creek
and Christina Lake, as well as new projects at Narrows Lake, Grand rapids and
Telephone Lake in order to achieve this objective.
As part of ongoing efforts to maintain financial resilience and flexibility,
Cenovus has taken steps to reduce pricing risk through a commodity hedging
program. While we have historically benefitted from this strategy, there is no
certainty that we will continue to derive such benefits in the future.
We will continue to develop our strategy with respect to capital investment
and returns to shareholders. Future dividends will be at the sole discretion of
the Board and considered quarterly.
75 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
Advisory
F Or WA r D - L O Ok I n G I n F Or m At I On
This MD&A contains certain forward-looking statements and other
information (collectively “forward-looking information”) about our current
expectations, estimates and projections, made in light of our experience and
perception of historical trends. Forward-looking information in this MD&A is
identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast”, or
“F”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”,
“outlook”, “potential”, “may” or similar expressions and includes suggestions of
future outcomes, including statements about our growth strategy and related
schedules, projected future value or net asset value, forecast operating and
financial results, planned capital expenditures, expected future production,
including the timing, stability or growth thereof, anticipated finding and
development costs, expected reserves and contingent and prospective
resources estimates, potential dividends and dividend growth strategy,
anticipated timelines for future regulatory, partner or internal approvals,
forecasted commodity prices, future use and development of technology and
projected increasing shareholder value. readers are cautioned not to place
undue reliance on forward-looking information as our actual results may
differ materially from those expressed or implied.
Developing forward-looking information involves reliance on a number of
assumptions and consideration of certain risks and uncertainties, some of
which are specific to Cenovus and others that apply to the industry generally.
The factors or assumptions on which the forward-looking information is
based include: assumptions inherent in our current guidance, available at
www.cenovus.com; our projected capital investment levels, the flexibility
of capital spending plans and the associated source of funding; estimates
of quantities of oil, bitumen, natural gas and liquids from properties and
other sources not currently classified as proved; ability to obtain necessary
regulatory and partner approvals; the successful and timely implementation
of capital projects; our ability to generate sufficient cash flow from
operations to meet our current and future obligations; and other risks
and uncertainties described from time to time in the filings we make with
securities regulatory authorities.
The risk factors and uncertainties that could cause our actual results to differ
materially, include: volatility of and assumptions regarding oil and gas prices;
the effectiveness of our risk management program, including the impact of
derivative financial instruments and our access to various sources of capital;
accuracy of cost estimates; fluctuations in commodity prices, currency and
interest rates; fluctuations in product supply and demand; market competition,
including from alternative energy sources; risks inherent in our marketing
operations, including credit risks; maintaining a desirable debt to cash flow
ratio; our ability to access external sources of debt and equity capital;
success of hedging strategies; accuracy of our reserves, resources and future
production estimates; our ability to replace and expand oil and gas reserves;
the ability of us and Conocophillips to maintain our relationship and to
successfully manage and operate our integrated heavy oil business; reliability
of our assets; potential disruption or unexpected technical difficulties in
developing new products and manufacturing processes; refining and marketing
margins; potential failure of new products to achieve acceptance in the
market; unexpected cost increases or technical difficulties in constructing
or modifying manufacturing or refining facilities; unexpected difficulties
in manufacturing, transporting or refining of crude oil into petroleum and
chemical products at two refineries; risks associated with technology and
its application to our business; the timing and the costs of well and pipeline
construction; our ability to secure adequate product transportation; changes
in Alberta’s regulatory framework, including changes to the regulatory approval
process and land-use designations, royalty, tax, environmental, greenhouse gas,
carbon and other laws or regulations, or changes to the interpretation of such
laws and regulations, as adopted or proposed, the impact thereof and the
costs associated with compliance; the expected impact and timing of various
accounting pronouncements, rule changes and standards on our business,
our financial results and our consolidated financial statements; changes in
the general economic, market and business conditions; the political and
economic conditions in the countries in which we operate; the occurrence of
unexpected events such as war, terrorist threats and the instability resulting
therefrom; and risks associated with existing and potential future lawsuits and
regulatory actions against us.
readers are cautioned that the foregoing lists are not exhaustive and are
made as at the date hereof. For a full discussion of our material risk factors,
see “risk Factors” in our Annual Information Form/Form 40-F for the year
ended December 31, 2010, available at www.sedar.com, www.sec.gov and
www.cenovus.com.
O I L A n D G A s I n F O r m At I O n
The bitumen contingent and prospective resources estimates were prepared
effective December 31, 2010 by McDaniel & Associates Consultants Ltd.,
an independent qualified reserves evaluator. The estimates were based
on the Canadian Oil and Gas Evaluation Handbook and comply with the
requirements of National Instrument 51-101.
• Contingent resources are 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. Contingencies may include such factors as
economic, legal, environmental, political and regulatory matters or a lack
of markets. It is also appropriate to classify as contingent resources the
estimated discovered recoverable quantities associated with a project in the
early evaluation stage. The estimate of contingent resources has not been
adjusted for risk based on the chance of development.
CENOVUS 201 0 A NNUA L rEpOr T · M ANAGEM E NT ’S DISC USSIO N AN D ANALYSIS · 76
• Economic Contingent resources are those contingent resources that
are currently economically recoverable based on specific forecasts of
commodity prices and costs. In Cenovus’s case, contingent resources were
evaluated using the same commodity price assumptions that were used for
the 2010 reserves evaluation, which comply with NI 51-101 requirements.
• prospective resources are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from undiscovered accumulations
by application of future development projects. prospective resources have
both an associated chance of discovery and a chance of development.
prospective resources are further subdivided in accordance with the level
of certainty associated with recoverable estimates assuming their discovery
and development and may be subclassified based on project maturity. The
estimate of prospective resources has not been adjusted for risk based on
the chance of discovery or the chance of development.
• Best Estimate is considered to be the best estimate of the quantity of
resources that will actually be recovered. It is equally likely that the
actual remaining quantities recovered will be greater or less than the best
estimate. Those resources that fall within the best estimate have a 50
percent confidence level that the actual quantities recovered will equal or
exceed the estimate.
• Low Estimate is considered to be a conservative estimate of the quantity
of resources that will actually be recovered. It is likely that the actual
remaining quantities recovered will exceed the low estimate. Those
resources at the low end of the estimate range have the highest degree
of certainty – a 90 percent confidence level – that the actual quantities
recovered will equal or exceed the estimate.
• High Estimate is considered to be an optimistic estimate of the quantity
of resources that will actually be recovered. It is unlikely that the actual
remaining quantities of resources recovered will meet or exceed the high
estimate. Those resources at the high end of the estimate range have a
lower degree of certainty – a 10 percent confidence level – that the actual
quantities recovered will equal or exceed the estimate.
The economic contingent resources were estimated on a project level. The high
and low estimates are arithmetic sums of multiple estimates which statistical
principles indicate may be misleading as to volumes that may actually be
recovered. The aggregated low estimate results shown may have a higher level
of confidence than the individual projects, and the aggregated high estimate
results shown may have a lower level of confidence than the individual projects.
Additional information relating to our oil and gas reserves and resources is
presented in our AIF for the year ended December 31, 2010, available at
www.sedar.com and on our website at www.cenovus.com.
C r u D E O I L , n G L s A n D n A t u r A L G A s C O n v E r s I O n s
In this document, certain natural gas volumes have been converted to barrels
of oil equivalent (“BOE”) on the basis of six Mcf to one bbl. BOE may be
misleading, particularly if used in isolation. A conversion ratio of one bbl to six
Mcf is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent value equivalency at the wellhead.
A B Br E v I At I O n s
The following is a summary of the abbreviations that have been used in
this document:
O i l a n d n at U R a l g a S l i q U i d S
bbl
barrel
bbls/d
barrels per day
Mbbls/d
thousand barrels per day
MMbbls million barrels
ngls
BOE
Natural gas liquids
barrel of oil equivalent
BOE/d
barrel of oil equivalent per day
Wti
WCS
West Texas Intermediate
Western Canada Select
n at U R a l g a S
Mcf
thousand cubic feet
MMcf
million cubic feet
MMcf/d million cubic feet per day
Bcf
billion cubic feet
MMBtu million British thermal units
gJ
Gigajoule
CBM
Coal Bed Methane
The Arrangement refers to the commencement of independent operations
on December 1, 2009 following an agreement with Encana creating two
independent publicly traded energy companies.
n O n - G A A P m E A s u r E s
Certain financial measures in this document do not have a standardized
meaning as prescribed by GAAp such as cash flow, operating cash flow, free
cash flow, operating earnings, adjusted EBITDA, debt and capitalization and
therefore are considered non-GAAp measures. These measures may not be
comparable to similar measures presented by other issuers. These measures
have been described and presented in this document in order to provide
shareholders and potential investors with additional information regarding
our liquidity and our ability to generate funds to finance our operations.
The additional information should not be considered in isolation or as a
substitute for measures prepared in accordance with GAAp. The definition
and reconciliation of each non-GAAp measure, is presented in this MD&A.
A D D I t I On A L I n F Or m At I On
For convenience, references in this document to “the Company”, “Cenovus”, “we”,
“us”, “our” and “its” may, where applicable, refer only to or include any relevant
direct and indirect subsidiary corporations and partnerships (“subsidiaries”) of
Cenovus, and the assets, activities and initiatives of such subsidiaries.
Additional information relating to Cenovus Energy Inc., including our AIF for
the year ended December 31, 2010, is available on SEDAr at www.sedar.com
and on our website at www.cenovus.com.
77 · MANAGEMENT ’S DISCUSSION AND ANALYSIS · CENOVUS 201 0 ANNUAL rEpOr T
COnSOlidatEd Fin anCial S
tatEMEnt S
report of management
m A n AG E m E n t ’ s r E s P O n s I B I L I t Y F O r t H E C O n s O L I DAt E D F I n A n C I A L s tAt E m E n t s
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. (“Cenovus”) are the responsibility of Management.
The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with Canadian
generally accepted accounting principles and include certain estimates that reflect Management’s best judgments.
The Board of Directors has approved the information contained in the
Consolidated Financial Statements. The Board of Directors fulfills its
responsibility regarding the financial statements mainly through its
Audit Committee which is made up of three independent directors. The
Audit Committee has a written mandate that complies with the current
requirements of Canadian securities legislation and the United States
Sarbanes-Oxley Act of 2002 and voluntarily complies, in principle, with the
Audit Committee guidelines of the New York Stock Exchange. The Audit
Committee meets with Management and the independent auditors at least
on a quarterly basis to review and approve interim Consolidated Financial
Statements and Management’s Discussion and Analysis prior to their release
as well as annually to review the annual Consolidated Financial Statements
and Management’s Discussion and Analysis and recommend their approval to
the Board of Directors.
m A n AG E m E n t ’ s A s s E s s m E n t O F I n t E r n A L C O n t r O L O v E r F I n A n C I A L r E P O r t I n G
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal
control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the
Consolidated Financial Statements.
Internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Management has assessed the design and effectiveness of internal control
over financial reporting as at December 31, 2010. In making its assessment,
Management has used the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”) framework in Internal Control–Integrated
Framework to evaluate the design and effectiveness of internal control over
financial reporting. Based on our evaluation, Management has concluded that
internal control over financial reporting was effective as at that date.
pricewaterhouseCoopers LLp, an independent firm of Chartered Accountants,
was appointed to audit and provide independent opinions on both the
Consolidated Financial Statements and internal control over financial
reporting as at December 31, 2010 as stated in their Auditors’ report.
pricewaterhouseCoopers LLp has provided such opinions.
Brian C. Ferguson
president & Chief Executive Officer
Cenovus Energy Inc.
February 18, 2011
CENOVUS 201 0 A NNUA L rEpOr T · rEpOr T OF MA NAGEM E NT · 78
ivor M. Ruste
Executive Vice-president & Chief Financial Officer
Cenovus Energy Inc.
Independent Auditor’s report
t O t H E s H A r E H O L D E r s O F C E n Ov u s E n E r G Y I n C .
We have completed integrated audits of Cenovus Energy Inc.’s 2010, 2009 and 2008 consolidated financial statements and its
internal control over financial reporting as at December 31, 2010. Our opinions, based on our audits, are presented below.
R E P O R t O n t h E C O n S O l i dat E d F i n a n C i a l S tat E M E n t S
We have audited the accompanying consolidated financial statements of
Cenovus Energy Inc., which comprise the consolidated balance sheets at
December 31, 2010 and December 31, 2009 and the consolidated statements
of earnings and comprehensive income, shareholders’ equity and cash flows
for each of the three years in the period ended December 31, 2010, and the
related notes including a summary of significant accounting policies.
M a n ag E M E n t ’ S R E S P O n S i B i l i t y F O R t h E C O n S O l i dat E d
F i n a n C i a l S tat E M E n t S
Management is responsible for the preparation and fair presentation of these
consolidated financial statements in accordance with Canadian generally
accepted accounting principles and for such internal control as management
determines is necessary to enable the preparation of consolidated financial
statements that are free from material misstatement, whether due to fraud
or error.
aU d i tO R ’ S R E S P O n Si B i l i t y
Our responsibility is to express an opinion on these consolidated financial
statements based on our audits. We conducted our audits in accordance with
Canadian generally accepted auditing standards and the standards of the
public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform an audit to obtain reasonable assurance
whether the consolidated financial statements are free from material
misstatement. Canadian generally accepted auditing standards require that
we comply with ethical requirements.
An audit involves performing procedures to obtain audit evidence, on a
test basis, about the amounts and disclosures in the consolidated financial
statements. The procedures selected depend on the auditors’ judgment,
including the assessment of the risks of material misstatement of the
consolidated financial statements, whether due to fraud or error. In making
those risk assessments, the auditor considers internal control relevant to the
company’s preparation and fair presentation of the consolidated financial
statements in order to design audit procedures that are appropriate in
the circumstances. An audit also includes evaluating the appropriateness
of accounting principles and policies used and the reasonableness of
accounting estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is
sufficient and appropriate to provide a basis for our audit opinion on the
consolidated financial statements.
OP i n i On
In our opinion, the consolidated financial statements present fairly, in
all material respects, the financial position of Cenovus Energy Inc. as at
December 31, 2010 and December 31, 2009 and the results of its operations
and cash flows for each of the three years in the period ended December 31,
2010 in accordance with Canadian generally accepted accounting principles.
R E P O R t O n i n t E R n a l C O n t R O l O v E R F i n a n C i a l R E P O R t i n g
We have also audited Cenovus Energy Inc.’s internal control over financial
reporting as at December 31, 2010, based on criteria established in Internal
Control - Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
79 · INDEpENDENT AUDITOr’ S rEpOr T · CENOVUS 2010 ANNUAL rEpOr T
M a n ag E M E n t ’ S R E S P O n S i B i l i t y F O R i n t E R n a l C O n t R O l O v E R
d E F i n i t i O n O F i n t E R n a l C O n t R O l O v E R F i n a n C i a l R E P O R t i n g
F i n a n C i a l R E P O R t i n g
The company’s management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in the accompanying
Management’s Assessment of Internal Controls over Financial reporting.
aU d i tO R ’ S R E S P O n Si B i l i t y
Our responsibility is to express an opinion on the company’s internal control
over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control
over financial reporting was maintained in all material respects.
An audit of internal control over financial reporting includes obtaining an
understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing
such other procedures as we consider necessary in the circumstances.
We believe that our audit provides a reasonable basis for our opinion on the
company’s internal control over financial reporting.
A company’s internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes
in accordance with Canadian generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the
assets of the company; (ii) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial statements in
accordance with Canadian generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in accordance
with authorizations of management and directors of the company; and (iii)
provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
i n h E R En t l iM i tat iO n S
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
OP i n i On
In our opinion, Cenovus Energy Inc. maintained, in all material respects,
effective internal control over financial reporting as at December 31, 2010
based on criteria established in Internal Control — Integrated Framework
issued by COSO.
PricewaterhouseCoopers llP
Chartered Accountants
Calgary, Alberta, Canada
February 18, 2011
CENOVUS 201 0 A NNUA L rEpOr T · IN DEpE N DE N T AUD ITOr’ S rEpOr T · 80
C O n s O L I DAt E D s tAt E m E n t s O F E A r n I n G s A n D C O m P r E H E n s I v E I n C O m E
For the years ended December 31, ($ millions, except per share amounts)
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
purchased product
Depreciation, depletion and amortization
General and administrative
Interest, net
Accretion of asset retirement obligation
Foreign exchange (gain) loss, net
(Gain) loss on divestiture of assets
Other (income) loss, net
Earnings Before Income Tax
Income tax expense
Net Earnings
Other Comprehensive Income (Loss), Net of Tax
Foreign currency translation adjustment
Comprehensive Income
Net Earnings per Common Share
Basic
Diluted
See accompanying Notes to Consolidated Financial Statements.
(Note 1)
(Note 1)
(Note 1)
(Note 8)
(Note 16)
(Note 9)
(Note 6)
(Note 10)
(Note 22)
2010
13,422
449
12,973
34
1,065
1,302
7,549
1,310
251
279
75
(51)
9
(13)
11,810
1,163
170
993
(13)
980
1.32
1.32
2009
11,790
273
11,517
44
760
1,312
5,910
1,527
211
244
45
304
–
(2)
10,355
1,162
344
818
(238)
580
1.09
1.09
2008
18,103
533
17,570
80
1,021
1,292
10,341
1,397
171
233
40
(308)
–
3
14,270
3,300
774
2,526
347
2,873
3.37
3.36
81 · C ONSOLIDATED S TATEMENTS OF E ArNINGS AND C OMprEHENSIVE INCOME · CENOVUS 201 0 ANNUAL rEpOr
T
C O n s O L I DAt E D B A L A n C E s H E E t s
As at December 31, ($ millions)
Assets
Current Assets
Cash and cash equivalents
Accounts receivable and accrued revenues
Income tax receivable
Current portion of partnership Contribution receivable
risk management
Inventories
Assets Held for Sale
property, plant and Equipment, net
partnership Contribution receivable
risk Management
Other Assets
Goodwill
Liabilities and shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities
Income tax payable
Current portion of partnership Contribution payable
risk management
Liabilities related to Assets Held for Sale
Long-Term Debt
partnership Contribution payable
risk Management
Asset retirement Obligation
Other Liabilities
Future Income Taxes
Commitments and Contingencies
Shareholders’ Equity
See accompanying Notes to Consolidated Financial Statements.
Approved by the Board
2010
2009
300
1,055
31
346
163
880
2,775
65 –
15,530
2,145
43 1
391
1,146
22,095
1,825
154 –
343
163
2,485
7 –
3,432
2,176
10 4
1,213
346
2,404
12,073
10,022
22,095
155
978
40
345
60
875
2,453
15,214
2,621
320
1,146
21,755
1,574
340
70
1,984
3,656
2,650
1,147
239
2,467
12,147
9,608
21,755
(Note 11)
(Note 21)
(Note 12)
(Note 6)
(Notes 1, 13)
(Note 11)
(Note 21)
(Note 14)
(Note 1)
(Note 11)
(Note 21)
(Note 6)
(Note 15)
(Note 11)
(Note 21)
(Note 16)
(Note 17)
(Note 10)
(Note 23)
(Note 18)
Michael a. grandin
Director
Cenovus Energy Inc.
Colin taylor
Director
Cenovus Energy Inc.
CENOVUS 201 0 A NNUA L rEpOr T · CON SOLIDATED BA L A NCE SH E E TS · 8 2
Share
Capital
(Note 18)
paid in
Surplus
(Note 18)
retained
Earnings
Owner’s Net
Investment
(Note 18)
AOCI*
C O n s O L I DAt E D s tAt E m E n t s O F s H A r E H O L D E r s ’ E Q u I t Y
($ millions)
Balance as at December 31, 2007
Net earnings
Net distribution to owner
Other comprehensive income (loss)
Balance as at December 31, 2008
Net earnings
Net distribution to owner
Other comprehensive income (loss)
Owner’s net Investment at Arrangement date –
november 30, 2009
Issuance of common stock in connection
with the Arrangement
reclassification of owner’s net investment to paid
in surplus in connection with the Arrangement
Net earnings – December 1 to December 31
Dividends on common shares
Common shares issued under option plans
Other comprehensive income (loss)
Balance as at December 31, 2009
Net earnings
Common shares issued under option plans
Dividends on common shares
Other comprehensive income (loss)
–
–
–
–
–
–
–
–
–
3,680
–
–
–
1
–
–
–
–
–
–
–
–
–
–
–
6,055
–
(159)
–
–
3,681
5,896
–
35
–
–
–
–
–
–
Balance as at December 31, 2010
3,716
5,896
* Accumulated Other Comprehensive Income
See accompanying Notes to Consolidated Financial Statements.
–
–
–
–
–
–
–
–
–
–
–
45
–
–
–
45
993
–
(601)
–
437
(123)
–
–
347
224
–
–
(212)
12
–
–
–
–
–
(26)
(14)
–
–
–
(13)
(27)
Total
7,912
2,526
(1,297)
347
9,488
773
(302)
(212)
8,035
2,526
(1,297)
–
9,264
773
(302)
–
9,735
9,747
(3,680)
(6,055)
–
–
–
–
–
–
–
–
–
–
–
–
45
(159)
1
(26)
9,608
993
35
(601)
(13)
10,022
83 · C ONSOLIDATED S TATEMENTS OF SHArEH OLDErS ’ EQUITY · CENOVUS 2010 ANNUAL rEpOr T
C O n s O L I DAt E D s tAt E m E n t s O F C A s H F L OW s
For the years ended December 31, ($ millions)
Operating Activities
Net earnings
Depreciation, depletion and amortization
Future income taxes (recovery)
Unrealized (gain) loss on risk management
Unrealized foreign exchange (gain) loss
Accretion of asset retirement obligation
(Gain) loss on divestiture of assets
Other
Net change in other assets and liabilities
Net change in non-cash working capital
Cash From Operating Activities
Investing Activities
Capital expenditures
proceeds from divestitures
Net change in other assets
Net change in non-cash working capital
Cash (Used in) Investing Activities
Net Cash provided before Financing Activities
Financing Activities
Net issuance (repayment) of revolving long-term debt
Issuance of long-term debt
repayment of long-term debt
Issuance of U.S. Unsecured Notes
payment of note payable to Encana
payment of transition account payable to Encana
Net financing transactions with Encana
Issuance of common shares
Dividends on common shares
Other
Cash (Used in) Financing Activities
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents
Held in Foreign Currency
Increase (Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents, Beginning of Year
Cash and Cash Equivalents, End of Year
Supplemental Cash Flow Information
See accompanying Notes to Consolidated Financial Statements.
2010
2009
2008
993
1,310
88
(46)
(69)
75
9
55
(55)
234
818
1,527
(590)
698
327
45
–
20
(26)
220
2,594
3,039
2,526
1,397
405
(899)
(317)
40
–
(37)
(92)
202
3,225
(2,208)
309
4
99
(1,796)
798
(58)
–
–
–
–
–
–
28
(601)
–
(631)
(22)
145
155
300
(2,165)
(2,204)
222
(25)
(95)
(2,063)
976
(342)
204
(97)
3,718
(3,701)
(264)
(302)
1
(159)
(35)
(977)
(32)
(33)
188
155
48
(49)
96
(2,109)
1,116
41
276
(247)
–
–
–
(1,297)
–
–
–
(1,227)
1
(110)
298
188
(Note 10)
(Note 21)
(Note 9)
(Note 16)
(Note 1)
(Note 7)
(Note 15)
(Note 15)
(Note 22)
CENOVUS 201 0 A NNUA L rEpOr T · CON SOLIDATED STATEM E NTS O F C AS H FLOWS · 84
nO tES t O COnSOlidatEd FinanCial S
tatEMEn t S
All amounts in $ millions, unless otherwise indicated.
For the year ended December 31, 2010
1. DEs CrIPtIOn OF BusInEss AnD sE GmEn tE D D Is
CLOsurEs
Cenovus Energy Inc. (“Cenovus” or the “Company”) is in the business of the
development, production and marketing of crude oil, natural gas and natural gas
liquids (“NGLs”) in Canada with refining operations in the United States (“U.S.”).
The Company is headquartered in Calgary, Alberta and its Common Shares
are listed on the Toronto and New York stock exchanges. Information on
the Company’s background and the basis of presentation for these financial
statements are found in Note 2.
The Company’s operating and reportable segments are as follows:
• Upstream, which includes Cenovus’s development and production
of crude oil, natural gas and NGLs in Canada, is organized into two
reportable operations:
– Oil Sands, which consists of Cenovus’s producing bitumen assets at
Foster Creek and Christina Lake, heavy oil assets at pelican Lake, new
resource play assets such as Narrows Lake, Grand rapids and Telephone
Lake, and the Athabasca natural gas assets. Certain of the Company’s oil
sands properties, notably Foster Creek, Christina Lake and Narrows Lake,
are jointly owned with Conocophillips, an unrelated U.S. public company
and operated by Cenovus.
– Conventional, which includes the development and production of
conventional crude oil, natural gas and NGLs in western Canada.
• Refining and Marketing, which is focused on the refining of crude
oil products into petroleum and chemical products at two refineries
located in the U.S. The refineries are jointly owned with and operated by
Conocophillips. This segment also markets Cenovus’s crude oil and natural
gas, as well as third-party purchases and sales of product that provide
operational flexibility for transportation commitments, product type,
delivery points and customer diversification.
• Corporate and Eliminations, which primarily includes unrealized gains
or losses recorded on derivative financial instruments as well as other
Cenovus-wide costs for general and administrative and financing activities.
As financial instruments are settled, the realized gains and losses are
recorded in the operating segment to which the derivative instrument
relates. Eliminations relate to sales and operating revenues and purchased
product between segments recorded at transfer prices based on current
market prices and to unrealized intersegment profits in inventory.
The operating and reportable segments shown above have been changed
from those presented in prior periods to match Cenovus’s new operating
structure. All prior periods have been restated to reflect this presentation.
The tabular financial information which follows presents the segmented
information first by segment, then by product and geographic location.
Capital expenditures, goodwill, sales information and information relating to
Cenovus’s major customers are summarized at the end of the note.
85 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
R E S U lt S O F O P E R at i O n S – S E g M E n t a n d O P E R at i O n a l i n F O R M at i O n
For the years ended December 31,
2010
2009
2008
2010
2009
2008
2010
2009
2008
Oil Sands
Conventional
Total Upstream
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
purchased product
Depreciation, depletion and amortization
Segment Income (Loss)
Balances as at December 31,
property, plant & Equipment
Goodwill
Total Assets
2,719
279
2,440
–
935
369
–
1,136
2,277
135
2,142
1
628
332
–
1,181
2,558
246
2,312
2
791
335
–
2,539
170
2,369
34
130
441
–
3,369
138
3,231
43
132
416
–
4,130
287
3,843
78
230
427
–
1,184
1,764
2,640
3,108
5,258
449
4,809
34
1,065
810
–
2,900
1,039
1,861
5,646
273
5,373
44
760
748
–
3,821
1,250
2,571
6,688
533
6,155
80
1,021
762
–
4,292
1,179
3,113
10,196
10,095
9,949
1,146
1,146
1,146
14,543
14,921
15,466
For the years ended December 31,
2010
2009
2008
2010
2009
2008
2010
2009
2008
refining and Marketing
Corporate and Eliminations
Consolidated
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
purchased product
Depreciation, depletion and amortization
Segment Income (Loss)
General and Administrative
Interest, net
Accretion of asset retirement obligation
Foreign exchange (gain) loss, net
(Gain) loss on divestiture of assets
Other (income) loss, net
Earnings Before Income Tax
Income tax expense
Net Earnings
Balances as at December 31,
property, plant & Equipment
Goodwill
Total Assets
8,228
–
8,228
–
–
489
7,664
75
239
(164)
6,922
–
6,922
–
–
534
6,020
368
232
136
10,684
–
10,684
–
–
543
10,500
(359)
205
(564)
5,188
5,003
4,967
–
–
–
6,714
6,404
5,964
(64)
–
(64)
–
–
3
(115)
48
32
16
251
279
75
(51)
9
(13)
550
146
–
838
(778)
–
(778)
–
–
30
(110)
(698)
45
(743)
211
244
45
304
–
(2)
802
731
–
731
–
–
(13)
(159)
903
13
890
171
233
40
(308)
–
3
139
13,422
449
12,973
34
1,065
1,302
7,549
3,023
1,310
1,713
251
279
75
(51)
9
(13)
550
1,163
170
993
11,790
273
11,517
44
760
1,312
5,910
3,491
1,527
1,964
211
244
45
304
–
(2)
802
1,162
344
818
18,103
533
17,570
80
1,021
1,292
10,341
4,836
1,397
3,439
171
233
40
(308)
–
3
139
3,300
774
2,526
116
–
98
–
15,530
15,214
15,014
1,146
1,146
1,146
430
1,184
22,095
21,755
22,614
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 86
U P S t R E a M P R O d U C t a n d O P E R at i O n a l i n F O R M at i O n
For the years ended December 31,
2010
2009
2008
2010
2009
2008
2010
2009
2008
Oil Sands
Crude Oil & NGLs
Conventional
Total
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
Operating Cash Flow
2,603
276
2,327
–
934
341
2,056
129
1,927
1
626
298
2,262
178
2,084
2
784
279
1,052
1,002
1,019
1,220
153
1,067
28
86
202
751
1,161
119
1,042
28
87
174
753
1,606
208
1,398
40
154
171
1,033
3,823
429
3,394
28
1,020
543
1,803
3,217
248
2,969
29
713
472
3,868
386
3,482
42
938
450
1,755
2,052
Oil Sands
Natural Gas
Conventional
Total
For the years ended December 31,
2010
2009
2008
2010
2009
2008
2010
2009
2008
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
Operating Cash Flow
102
1
101
–
1
23
77
214
6
208
–
2
25
181
278
68
210
–
7
43
160
1,306
17
1,289
6
44
235
2,196
19
2,177
15
45
237
2,512
79
2,433
38
76
252
1,408
18
1,390
6
45
258
2,410
25
2,385
15
47
262
2,790
147
2,643
38
83
295
1,004
1,880
2,067
1,081
2,061
2,227
Oil Sands
Other
Conventional
Total
For the years ended December 31,
2010
2009
2008
2010
2009
2008
2010
2009
2008
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
Operating Cash Flow
14
2
12
–
–
5
7
7
–
7
–
–
9
(2)
18
–
18
–
–
13
5
13
–
13
–
–
4
9
12
–
12
–
–
5
7
12
–
12
–
–
4 9
8
Oil Sands
Total
Conventional
30
–
30
–
–
17
13
27
2
25
–
–
16
19
–
19
–
–
14
5
Total
For the years ended December 31,
2010
2009
2008
2010
2009
2008
2010
2009
2008
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
Operating Cash Flow
2,719
279
2,440
–
935
369
1,136
2,277
135
2,142
1
628
332
1,181
2,558
246
2,312
2
791
335
1,184
2,539
170
2,369
34
130
441
3,369
138
3,231
43
132
416
4,130
287
3,843
78
230
427
5,258
449
4,809
34
1,065
810
5,646
273
5,373
44
760
748
6,688
533
6,155
80
1,021
762
1,764
2,640
3,108
2,900
3,821
4,292
87 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
g E O g R a P h i C i n F O R M at i On
The refining and Marketing segment operates in both Canada and the United
States. Both of Cenovus’s refining facilities are located and carry on business
in the United States. The marketing of Cenovus’s crude oil and natural gas
produced in Canada, as well as the third party purchases and sales of product
is undertaken in Canada. physical product sales that settle in the United
States are considered to be export sales undertaken by a Canadian business.
Canada (Marketing)
United States (refining)
Total
refining and Marketing
For the years ended December 31,
2010
2009
2008
2010
2009
2008
2010
2009
2008
Gross revenues
Less: royalties
Net revenues
Expenses
Operating
purchased product
Operating Cash Flow
Depreciation, depletion and amortization
Segment Income (Loss)
1,604
–
1,604
17
1,579
8
10
(2)
965
–
965
17
938
10
12
(2)
1,211
–
1,211
20
1,184
7
4
3
6,624
5,957
9,473
8,228
6,922
10,684
–
–
–
–
–
–
6,624
5,957
9,473
8,228
6,922
10,684
472
517
6,085
5,082
67
229
(162)
358
220
138
523
9,316
(366)
201
(567)
489
534
543
7,664
6,020
10,500
75
239
(164)
368
232
136
(359)
205
(564)
C a P i ta l E x P E n d i t U R E S
For the years ended December 31,
Capital
Oil Sands
Conventional
Upstream
refining and Marketing
Corporate
Acquisition Capital
Oil Sands
Conventional
refining and Marketing
Total
2010
2009
2008
867
523
1,390
656
76
2,122
25
23
38
629
466
1,095
1,033
34
2,162
–
3
–
758
848
1,606
539
59
2,204
–
–
–
2,208
2,165
2,204
In addition to the above, in 2009 Cenovus acquired strategic bitumen lands in
exchange for certain non-core holdings.
g O Od W i l l a d d i t i On S
There were no additions to goodwill during 2010, 2009 or 2008.
E x P O R t S a l E S
Sales of crude oil, natural gas and NGLs produced or purchased in Canada
delivered to customers outside of Canada were $646 million (2009–$618
million; 2008–$1,388 million).
M a J O R C U S tO M E R S
In connection with the marketing and sale of Cenovus’s own and purchased
crude oil, natural gas and refined products for the year ended December 31,
2010, Cenovus had two customers (2009–two; 2008–two) which individually
accounted for more than 10 percent of its consolidated gross revenues. Sales
to these customers, major international integrated energy companies with an
investment grade credit rating, were approximately $7,671 million (2009–
$6,389 million; 2008–$9,619 million).
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 88
2 . BACk Gr OunD & BAsIs OF PrEsEn t AtIOn
In these Consolidated Financial Statements, unless otherwise indicated, all
dollars are expressed in Canadian dollars. The Company’s functional currency
is Canadian dollars. All references to C$ or $ are to Canadian dollars and
references to US$ are to U.S. dollars.
Cenovus began independent operations on December 1, 2009, as a result
of the plan of arrangement (“Arrangement”) involving Encana Corporation
(“Encana”) whereby Encana was split into two independent energy companies,
one a natural gas company, Encana and the other an oil company, Cenovus.
In connection with the Arrangement, Encana common shareholders received
one share in each of the new Encana and Cenovus in exchange for each
Encana share held. Common shares of Cenovus began trading on a “when
issued” basis on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges
on November 2, 2009. regular trading of the Cenovus shares began on the
TSX on December 3, 2009 and on the NYSE on December 9, 2009.
Up until the completion of the Arrangement, Encana was considered a related
party due to its parent-subsidiary relationship with the Cenovus entities.
However, subsequent to the Arrangement, Encana is no longer a related party
as defined by the CICA Handbook Section 3840 – related party Transactions.
B a S i S O F P R E S E n tat i O n /C a Rv E- O U t F i n a n C i a l i n F O R M at i O n
The results for the year ended December 31, 2010 and the one month period
from December 1 to December 31, 2009 represent the Company’s operations,
cash flow and financial position as a stand-alone entity. The results for the
periods prior to the Arrangement, being from January 1 to November 30, 2009
and January 1 to December 31, 2008 have been prepared on a “carve-out”
accounting basis whereby the results have been derived from the accounting
records of Encana using the historical results of operations and historical
basis of assets and liabilities of the businesses transferred to Cenovus.
As the Company operated as part of Encana and was not a stand-alone entity
prior to November 30, 2009, the historical Consolidated Financial Statements
include allocations of certain Encana revenues, expenses, assets and liabilities,
including the items described below.
The operating results of Cenovus were specifically identified based on
Encana’s divisional organization. Certain other expenses presented in the
Consolidated Statements of Earnings and Comprehensive Income represent
allocations and estimates of the cost of services incurred by Encana. These
allocations and estimates include unrealized mark-to-market gains and losses,
general and administrative costs, net interest, foreign exchange gains and
losses and income tax expenses. The majority of the assets and liabilities of
Cenovus were identified based on the divisional structure, with the most
significant exceptions being property, plant and equipment (“pp&E”), income
taxes payable and long-term debt.
refining, crude oil and natural gas marketing and corporate depreciation,
depletion and amortization were specifically identified based on Encana’s
divisional structure where possible. Depletion related to upstream properties
was allocated to Cenovus based on the related production volumes utilizing
the depletion rate calculated for Encana’s consolidated Canadian cost centre.
Mark-to-market gains and losses resulting from derivative financial
instruments entered into by Encana were allocated to Cenovus based on the
related product volumes.
Salaries, benefits, pension, long-term incentives and other post-employment
benefits costs, assets and liabilities were allocated to Cenovus based on
Management’s best estimate of how services were historically provided
by existing employees. Costs, assets and liabilities associated with retired
employees remained with Encana.
Net interest expense was calculated primarily using the debt balance
allocated to Cenovus.
Income taxes were recorded as if Cenovus and its subsidiaries had been separate
tax paying legal entities, each filing a separate tax return in its local jurisdiction.
The calculation of income taxes is based on a number of assumptions,
allocations and estimates, including those used to prepare the Cenovus
Carve-out Consolidated Financial Statements. prior to the Arrangement,
Cenovus’s tax pools were allocated for the Canadian cost centre based on the
same allocation method used to determine pp&E for carve-out purposes.
pp&E related to upstream oil and gas activities are accounted for by Cenovus
using the full cost method of accounting. pp&E related to upstream oil and
gas activities was determined based on an allocation process which used
the ratio of future net revenue, discounted at 10 percent, of the respective
divisions of Encana to the future net revenue, discounted at 10 percent, of all
proved properties in Canada at December 31, 2008. Future net revenue was
the estimated net amount to be received with respect to development and
production of crude oil and natural gas reserves.
Goodwill was allocated to Cenovus based on the properties associated with
the former business combinations on which it arose.
For the purpose of preparing the Carve-out Consolidated Financial
Statements, it was determined that Cenovus should maintain approximately
the same Debt to Capitalization ratio as consolidated Encana based on U.S.
dollar amounts. As a result, prior to the Arrangement, debt was allocated
to Cenovus based on this ratio, which was calculated using U.S. dollars.
Debt is defined as the current and long-term portions of Long-term Debt.
Capitalization is not a term that has a prescribed meaning under generally
accepted accounting principles (“non-GAAp”) and is a measure defined as
Debt plus Shareholders’ Equity.
Management believes the assumptions underlying the Cenovus Carve-out
Consolidated Financial Statements are reasonable. However, the Cenovus
Consolidated Financial Statements herein may not reflect Cenovus’s financial
position, results of operations, and cash flows had Cenovus been a stand-alone
company during the periods presented or what Cenovus’s operations, financial
position, and cash flows will be in the future. Encana’s direct investment in
89 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
Cenovus is shown as Net Investment in place of Shareholders’ Equity because a
direct ownership by shareholders in Cenovus did not exist prior to November
30, 2009. Encana’s investment includes the accumulated net earnings, other
comprehensive income and net cash distributions to Encana.
In the opinion of Management, the Consolidated and the historical Carve-out
Consolidated Financial Statements reflect all adjustments (including normal
recurring adjustments) necessary for a fair statement of the financial position
and the results of operations and cash flows in accordance with Canadian
generally accepted accounting principles (“Canadian GAAp”).
3. CHAnGE In rEPOrtInG Cu r rEnC Y
As a result of the Arrangement, Cenovus reported its results in U.S. dollars for
the preparation of its December 31, 2009 consolidated financial statements
as this was the reporting currency used by Encana. Effective January 1, 2010,
the Company changed its reporting currency to Canadian dollars. The change
in reporting currency is to better reflect the business of Cenovus, and it
allows for increased comparability to the Company’s peers. In implementing
this change, the Company has followed the requirements of the Canadian
Institute of Chartered Accountants (“CICA”) Emerging Issues Committee
(“EIC”) Abstract 130 (“EIC-130”), “Translation Method When the reporting
Currency Differs from the Measurement Currency or there is a Change in the
reporting Currency.”
With the change in reporting currency, all comparative financial information
has been restated from U.S. dollars to Canadian dollars to reflect the
Company’s consolidated financial statements as if they had been historically
reported in Canadian dollars.
4. summAr Y OF sIGnIFICAnt ACCOuntInG PO L I CI Es
A) principles of Consolidation
The Consolidated Financial Statements include the accounts of Cenovus
and its subsidiaries and are presented in accordance with Canadian GAAp.
Information prepared in accordance with GAAp in the United States is
included in Note 24.
Investments in jointly controlled partnerships and unincorporated joint
ventures carry on certain of Cenovus’s development, production and crude
oil refining businesses and are accounted for using the proportionate
consolidation method, whereby Cenovus’s proportionate share of revenues,
expenses, assets and liabilities are included in the accounts.
B) Foreign Currency Translation
The accounts of self-sustaining operations are translated using the current
rate method, whereby assets and liabilities are translated at period end
exchange rates, while revenues and expenses are translated using average
rates over the period. Translation gains and losses relating to the self-
sustaining operations are included in Accumulated Other Comprehensive
Income (“AOCI”) as a separate component of Shareholders’ Equity.
Monetary assets and liabilities of Cenovus that are denominated in foreign
currencies are translated into its functional currency at the rates of exchange
in effect at the period end date. Any gains or losses are recorded in the
Consolidated Statement of Earnings.
C) Measurement Uncertainty
and liabilities and disclosures of contingent assets and liabilities at the date
of the Consolidated Financial Statements and the reported amounts of
revenues and expenses during the period. Such estimates primarily relate
to unsettled transactions and events as of the date of the Consolidated
Financial Statements. Accordingly, actual results may differ from estimated
amounts as future confirming events occur.
Amounts recorded for depreciation, depletion and amortization, asset
retirement costs and obligations and amounts used for ceiling test and
impairment calculations are based on estimates of crude oil and natural gas
reserves, future costs required to develop those reserves and future cash
flows. By their nature, these estimates of reserves, including the estimates
of future prices and costs, and the related future cash flows are subject to
measurement uncertainty, and the impact in the Consolidated Financial
Statements of future periods could be material.
The values of pension assets and obligations and the amount of pension
costs charged to net earnings depend on certain actuarial and economic
assumptions which, by their nature, are subject to measurement uncertainty.
The amount of compensation expense accrued for long-term performance-
based compensation arrangements is subject to Management’s best estimate
of whether or not the performance criteria will be met and what the ultimate
payout will be.
The estimated fair value of financial assets and liabilities, by their very nature,
are subject to measurement uncertainty.
The timely preparation of the Consolidated Financial Statements in
conformity with Canadian GAAp requires that Management make estimates
and assumptions and use judgment regarding the reported amounts of assets
Tax regulations and legislation and the interpretations thereof in the various
jurisdictions in which Cenovus operates are subject to change. As such,
income taxes are subject to measurement uncertainty.
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 90
D) revenue recognition
H) Income Taxes
revenues associated with the sales of Cenovus’s crude oil, natural gas, NGLs
and petroleum and refined products are recognized when title passes from
the Company to its customer. realized gains and losses from crude oil and
natural gas commodity price risk management activities are recorded in
revenue when the product is sold.
revenues and purchased product are recorded on a gross basis when
the title to product passes and the risks and rewards of ownership have
been transferred. purchases and sales of products that are entered into in
contemplation of each other with the same counterparty are recorded on
a net basis. revenues associated with the services provided as agent are
recorded as the services are provided.
Unrealized gains and losses from natural gas and crude oil commodity price
risk management activities are recorded as revenue based on the related
mark-to-market calculations at the end of the respective period.
E) production and Mineral Taxes
Costs paid to non-mineral interest owners based on production of crude oil,
natural gas and NGLs are recognized when the product is produced.
F) Transportation and Blending Costs
The costs associated with the transportation of crude oil, natural gas and
NGLs, including the cost of diluent used in blending, are recognized when the
product is delivered and the services provided.
G) Employee Benefit plans
Accruals for obligations under the employee benefit plans and the related
costs are recorded net of plan assets.
The cost of pensions and other post-employment benefits is actuarially
determined using the projected benefit method based on length of service, and
reflects Management’s best estimate of expected plan investment performance,
salary escalation, retirement ages of employees and expected future health care
costs. The expected return on plan assets is based on the fair value of those
assets. The accrued benefit obligation is discounted using the market interest
rate on high quality corporate debt instruments as at the measurement date.
pension expense for the defined benefit pension plan includes the cost of
pension benefits earned during the current year, the interest cost on pension
obligations, the expected return on pension plan assets, the amortization of
the net transitional obligation, the amortization of adjustments arising from
pension plan amendments and the amortization of the excess of the net
actuarial gain or loss over 10 percent of the greater of the benefit obligation
and the fair value of plan assets. Amortization is calculated on a straight-line
basis over a period covering the expected average remaining service lives of
employees covered by the plans.
pension expense for the defined contribution pension plans is recorded as
the benefits are earned by the employees covered by the plans.
Cenovus follows the liability method of accounting for income taxes,
where future income taxes are recorded for the effect of any difference
between the accounting and income tax basis of an asset or liability, using
the substantively enacted income tax rates. Accumulated future income
tax balances are adjusted to reflect changes in income tax rates that are
substantively enacted with the adjustment being recognized in net earnings
in the period that the change occurs.
I) Earnings per Share Amounts
Basic net earnings per common share is computed by dividing the net
earnings by the weighted average number of common shares outstanding
during the period. Diluted net earnings per share amounts are calculated
giving effect to the potential dilution that would occur if stock options,
without tandem stock appreciation rights attached, were exercised or
other contracts expected to result in the issuance of common shares were
exercised or converted to common shares. The treasury stock method is
used to determine the dilutive effect of stock options without tandem share
appreciation rights attached and other dilutive instruments. The treasury
stock method assumes that proceeds received from the exercise of in-the-
money stock options without tandem stock appreciation rights attached are
used to repurchase common shares at the average market price.
J) Cash and Cash Equivalents
Cash and cash equivalents include short-term investments, such as money
market deposits or similar type instruments, with a maturity of three months
or less when purchased.
K) Inventories
product inventories, including petroleum and refined products, are valued at
the lower of cost and net realizable value on a first-in, first-out or weighted
average cost basis.
L) property, plant and Equipment
Upstream
Crude oil and natural gas properties are accounted for in accordance with the
CICA guideline on full cost accounting in the oil and gas industry. Under this
method, all costs, including internal costs and asset retirement costs, directly
associated with the acquisition of, the exploration for, and the development
of bitumen, crude oil and natural gas reserves, are capitalized on a country-
by-country cost centre basis.
Costs accumulated within each cost centre are depreciated, depleted and
amortized using the unit-of-production method based on estimated proved
reserves determined using estimated future prices and costs. For purposes
of this calculation, natural gas is converted to oil on an energy equivalent
basis. Capitalized costs subject to depletion include estimated future costs to
be incurred in developing proved reserves. proceeds from the divestiture of
91 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
properties are normally deducted from the full cost pool without recognition
of gain or loss unless that deduction would result in a change to the rate
of depreciation, depletion and amortization of 20 percent or greater, in
which case a gain or loss is recorded. Costs of major development projects
and costs of acquiring and evaluating significant unproved properties are
excluded, on a cost centre basis, from the costs subject to depletion until
it is determined whether or not proved reserves are attributable to the
properties, or impairment has occurred. Costs that have been impaired are
included in the costs subject to depreciation, depletion and amortization.
An impairment loss is recognized in net earnings when the carrying amount
of a cost centre is not recoverable and the carrying amount of the cost
centre exceeds its fair value. The carrying amount of the cost centre is not
recoverable if the carrying amount exceeds the sum of the undiscounted
cash flows from proved reserves. If the sum of the cash flows is less than
the carrying amount, the impairment loss is limited to the amount by which
the carrying amount exceeds the sum of:
i. the fair value of proved and probable reserves; and
ii. the costs of unproved properties that have been subject to a separate
impairment test.
Refining
The initial acquisition costs of refining property, plant and equipment
are capitalized when incurred. Costs include the cost of constructing or
otherwise acquiring the equipment or facilities, the cost of installing the
asset and making it ready for its intended use and the associated asset
retirement costs. Capitalized costs are not subject to depreciation until the
asset is put into use, after which they are depreciated on a straight-line basis
over the estimated service lives of each component of the refining facilities.
An impairment loss is recognized on refining property, plant and equipment
when the carrying amount is not recoverable and exceeds its fair value. The
carrying amount is not recoverable if the carrying amount exceeds the sum of
the undiscounted cash flows from expected use and eventual disposition. If
the carrying amount is not recoverable, an impairment loss is measured as the
amount by which the carrying amount exceeds the fair value.
Other
Costs associated with office furniture, fixtures, leasehold improvements,
information technology and aircraft are carried at cost and depreciated on
a straight-line basis over the estimated service lives of the assets, which
range from three to 25 years. Assets under construction are not subject to
depreciation until put into use.
M) Capitalization of Costs
Expenditures related to renewals or betterments that improve the productive
capacity or extend the life of an asset are capitalized. Maintenance and
repairs are expensed as incurred.
N) Amortization of Other Assets
Items included in Other Assets are amortized, where applicable, on a straight-
line basis over the estimated useful lives of the assets.
O) Goodwill
Goodwill, which represents the excess of purchase price over fair value of
net assets acquired, is assessed for impairment at least annually. Goodwill and
all other assets and liabilities have been allocated to the country cost centre
level, referred to as a reporting unit. To assess impairment, the fair value of the
reporting unit is determined and compared to the book value of the reporting
unit. If the fair value of the reporting unit is less than the book value, then a
second test is performed to determine the amount of the impairment. The
amount of the impairment is determined by deducting the fair value of the
reporting unit’s assets and liabilities from the fair value of the reporting unit to
determine the implied fair value of goodwill and comparing that amount to the
book value of the reporting unit’s goodwill. Any excess of the book value of
goodwill over the implied fair value of goodwill is the impairment amount.
p) Asset retirement Obligation
The fair value of estimated asset retirement obligations is recognized in the
Consolidated Balance Sheets when incurred and a reasonable estimate of fair
value can be made.
Asset retirement obligations include those legal obligations where Cenovus
will be required to retire tangible long-lived assets such as producing well
sites, crude oil and natural gas processing plants, and refining facilities. The
asset retirement cost, equal to the initially estimated fair value of the asset
retirement obligation, is capitalized as part of the cost of the related long-lived
asset. Changes in the estimated obligation resulting from revisions to estimated
timing or amount of undiscounted cash flows are recognized as a change in the
asset retirement obligation and the related asset retirement cost.
Amortization of asset retirement costs are included in depreciation,
depletion and amortization in the Consolidated Statements of Earnings.
Increases in the asset retirement obligation resulting from the passage of time
are recorded as accretion of asset retirement obligation in the Consolidated
Statements of Earnings.
Actual expenditures incurred are charged against the accumulated obligation.
Q) Stock-Based Compensation
Obligations for payments, cash or common shares, under Cenovus’s stock
option, performance share unit and deferred share unit plans are accrued
using the intrinsic method as compensation cost over the vesting period.
Fluctuations in the price of Cenovus’s common shares change the accrued
compensation cost and are recognized when they occur.
Encana replacement stock options with tandem stock appreciation rights
attached held by Cenovus employees are accrued using the fair value
method. The fair value is recognized as compensation cost over the vesting
period. Fluctuations in the fair value of the rights change the accrued
compensation cost and are recognized when they occur.
r) Financial Instruments
Financial instruments are measured at fair value on initial recognition of the
instrument. Measurement in subsequent periods depends on whether the
financial instrument has been classified as “held-for-trading”, “available-for-
sale”, “held-to-maturity”, “loans and receivables”, or “other financial liabilities”.
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 92
Financial assets and financial liabilities “held-for-trading” are measured at fair
value with changes in those fair values recognized in net earnings. Financial
assets “available-for-sale” are measured at fair value, with changes in those fair
values recognized in Other Comprehensive Income (“OCI”). Financial assets
“held-to-maturity”, “loans and receivables” and “other financial liabilities” are
measured at amortized cost using the effective interest method of amortization.
Cash and cash equivalents are designated as “held-for-trading” and are
measured at fair value. Accounts receivable and accrued revenues and
the partnership Contribution receivable and partner loans receivable
are designated as “loans and receivables”. Accounts payable and accrued
liabilities, the partnership Contribution payable and partner loans payable and
long-term debt are designated as “other financial liabilities”. Long-term debt
transaction costs, premiums and discounts are capitalized within long-term
debt and amortized using the effective interest method.
rates and interest rates. Derivative financial instruments are not used for
speculative purposes.
policies and procedures are in place with respect to the required documentation
and approvals for the use of derivative financial instruments and specifically
ties their use, in the case of commodities, to the mitigation of market price risk
associated with cash flows expected to be generated from budgeted capital
programs, and in other cases to the mitigation of market price risks for specific
assets and obligations. When applicable, the Company identifies relationships
between financial instruments and anticipated transactions, as well as its risk
management objective and the strategy for undertaking the economic hedge
transaction. Where specific financial instruments are executed, the Company
assesses, both at the time of purchase and on an ongoing basis, whether the
financial instrument used in the particular transaction is effective in offsetting
changes in fair values or cash flows of the transaction.
derivative Financial instruments
S) reclassification
risk management assets and liabilities are derivative financial instruments
classified as “held-for-trading” unless designated for hedge accounting. Derivative
instruments that do not qualify as hedges, or are not designated as hedges, are
recorded using mark-to-market accounting whereby instruments are recorded
in the Consolidated Balance Sheets as either an asset or liability with changes
in fair value recognized in net earnings. realized gains or losses from financial
derivatives related to crude oil and natural gas commodity prices are recognized
in crude oil and natural gas revenues as the related sales occur. realized gains
or losses from financial derivatives related to power commodity prices are
recognized in operating costs as the related power costs are incurred. Unrealized
gains and losses are recognized at the end of each respective reporting period.
The estimated fair value of all derivative instruments is based on quoted market
prices or, in their absence, third-party market indications and forecasts.
Derivative financial instruments are used to manage economic exposure
to market risks relating to commodity prices, foreign currency exchange
In addition to the restatement required due to the changes in operating
segments (see Note 1), certain information provided for prior years has been
reclassified to conform to the presentation adopted in 2010.
T) recent Accounting pronouncements
Beginning with the three month period ending March 31, 2011, Cenovus is
required to report its results in accordance with International Financial
reporting Standards (“IFrS”). Cenovus has developed a detailed changeover
plan to complete the transition to IFrS. The plan includes the preparation
of required comparative information for 2010, given that the IFrS date of
transition was January 1, 2010. The Company is on schedule with its plan and
is continuing to assess the potential impact of the adoption of IFrS on its
Consolidated Financial Statements.
5. CHAnGEs In ACCOu n tInG PO LI C IEs AnD PrACtI CEs
B U S i n E S S C O M B i n at i O n S
On January 1, 2010, Cenovus early adopted CICA Handbook Section 1582,
“Business Combinations,” which replaces CICA Handbook Section 1581 of
the same name. The new standard requires assets and liabilities acquired
in a business combination, contingent consideration and certain acquired
contingencies to be measured at their fair values as of the date of acquisition.
In addition, acquisition-related and restructuring costs are to be recognized
separately from the business combination and included in the Statement
of Earnings. This accounting policy was applied to the November 1, 2010
purchase of the marine terminal facilities disclosed in Note 6.
C O n S O l i dat E d F i n a n C i a l S tat E M E n t S a n d
n O n - C O n tR O l l i n g in tE R E S t S
In conjunction with the early adoption of CICA Handbook Section 1582, the
Company was also required to early adopt CICA Handbook Sections 1601,
“Consolidated Financial Statements” and 1602, “Non-controlling Interests”
effective January 1, 2010. These sections replace the former consolidated
financial statement standard, CICA Handbook Section 1600, “Consolidated
Financial Statements.” Section 1601 establishes the requirements for the
preparation of the consolidated financial statements and Section 1602
establishes the accounting for a non-controlling interest in a subsidiary in
consolidated financial statements subsequent to a business combination.
Section 1602 requires a non-controlling interest to be classified as a separate
component of equity. In addition, net earnings, and components of other
comprehensive income are attributed to both the parent and non-controlling
interest. The early adoption of these standards did not have a material impact
on the Company’s Consolidated Financial Statements for the year ended
December 31, 2010. These standards along with CICA Handbook Section 1582
above are converged with IFrS (see Note 4).
93 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
6. AssEts AnD LIABILItIEs HE LD FOr sA L E
On November 1, 2010, under the terms of an agreement with a non-related
Canadian company, Cenovus acquired certain marine terminal facilities in
Kitimat, British Columbia for cash consideration of $38 million.
Cenovus intends to sell the facilities as soon as practicable. As a result, the
net assets acquired have been recorded at estimated fair value less costs to
sell, and have been classified as held for sale. These assets are reported in the
refining and Marketing segment. Cenovus recognized a bargain purchase gain
of $12 million, resulting from the excess fair value of the net assets acquired
over the cash consideration paid. The table below represents the purchase
cost and the preliminary allocation to the assets and liabilities. The gain has
been recorded in other income.
Cash consideration
Fair value of Liabilities assumed
Asset retirement obligation
Future income taxes
Total purchase price and Liabilities Assumed
Estimated Fair Value of Assets acquired
property, plant and Equipment
Bargain purchase Gain
As at December 31, 2010 the assets and liabilities classified as held for sale consists of the following:
Assets Held for Sale
property, plant and equipment
Liabilities related to Assets Held for Sale
Asset retirement obligation
Future income taxes
7. DIvEstIturEs
For the years ended December 31,
Oil Sands
Conventional
Corporate
Cash proceeds
38
5
4
47
59
12
December 31, 2010
65
5
2
7
2010
2009
2008
81
221
7
309
89
130
3
222
8
40
–
48
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 94
8. In tErEst , nEt
For the years ended December 31,
Interest Expense–Long-Term Debt
Interest Expense–Other
Interest Income
2010
2009
2008
227
196
(144)
279
211
220
(187)
244
205
228
(200)
233
Interest Expense–Other and Interest Income are primarily due to the partnership Contribution payable and receivable, respectively (See Note 11).
9. FOrEIGn E XCHAnGE (GAIn) LO ss , nEt
For the years ended December 31,
Unrealized Foreign Exchange (Gain) Loss on translation of:
U.S. dollar debt issued from Canada
U.S. dollar partnership Contribution receivable issued from Canada
Other
Unrealized Foreign Exchange (Gain) Loss
realized Foreign Exchange (Gain) Loss
10. InCOmE t AXEs
The provision for income taxes is as follows:
For the years ended December 31,
Current
Canada
United States
Total Current Tax
Future Tax
2010
2009
2008
(182)
91
22
(69)
18
(51)
(381)
504
204
327
(23)
304
430
(744)
(3)
(317)
9
(308)
2010
2009
2008
82
–
82
88
170
979
(45)
934
(590)
344
393
(24)
369
405
774
Future income tax expense in 2010 includes a tax benefit of $107 million
from the recognition of net capital losses expected to be realized against
future capital gains. These net capital losses are attributable to an internal
restructuring undertaken in 2010. Net capital losses of $415 million, attributable
to the restructuring and to realized foreign exchange losses, are unrecognized at
December 31, 2010. recognition is dependent on the level of future capital gains.
Current income tax expense in 2009 includes the incremental tax incurred as
a result of certain corporate restructuring transactions which were required
to effect the Arrangement.
95 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
For the years ended December 31,
Earnings Before Income Tax
Canadian Statutory rate
Expected Income Tax
Effect on Taxes resulting from:
Statutory and other rate differences
Non-deductible stock-based compensation
Multi-jurisdictional financing
Foreign exchange gains not included in net earnings
Non-taxable capital (gains) losses
recognition of capital losses
Other
Effective Tax rate
The net future income tax liability consists of:
As at December 31,
Future Tax Liabilities
property, plant and equipment in excess of tax values
Timing of partnership items
Net foreign exchange gains
risk management
Other
Future Tax Assets
Unused tax losses
risk management
Other
Net Future Income Tax Liability
The approximate amounts of tax pools available are as follows:
As at December 31,
Canada
United States
2010
1,163
28.2%
328
(33)
29
(93)
28
(9)
(107)
27
170
14.6%
2009
1,162
29.2%
339
(1)
–
(134)
58
30
–
52
344
29.6%
2008
3,300
29.7%
980
(92)
–
(135)
71
(53)
–
3
774
23.5%
2010
2009
2,534
2,654
125
127
55
55
(281)
(45)
9
61
17
1
(242)
(33)
(166)
–
2,404
2,467
2010
4,239
3,082
7,321
2009
3,754
2,637
6,391
Included in the above tax pools are $236 million (2009–$491 million) of Canadian
non-capital losses which expire no earlier than 2026 and $607 million (2009–
$232 million) of U.S. net operating losses which expire no earlier than 2029.
Also included in the above tax pools are $983 million (2009–$51 million)
of Canadian net capital losses, available for carry forward to reduce future
capital gains.
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 96
11. PArtnErsHIP COn trIBu tIOn rE CE Iv
A BL E AnD PAYAB LE
In connection with the Arrangement with Encana, Cenovus acquired Encana’s
assets which are jointly controlled with Conocophillips. On January 2, 2007,
Encana became a 50 percent partner in an integrated, North American oil
business with Conocophillips which consists of an upstream entity and a
refining entity. The upstream entity contribution included assets from Encana,
primarily the Foster Creek and Christina Lake properties, with a fair value of
US$7.5 billion and a note receivable (partnership Contribution receivable)
contributed from Conocophillips of an equal amount. For the refining entity,
Conocophillips contributed its Wood river and Borger refineries, located in
Illinois and Texas, respectively, for a fair value of US$7.5 billion and Encana
contributed a note payable (partnership Contribution payable) of US$7.5 billion.
In accordance with Canadian GAAp, these entities have been accounted for
using the proportionate consolidation method with the results of operations
included in the Upstream and refining and Marketing segments (See Note 1).
Pa R t n E R Sh iP C O n tRiB Ut i O n R E C E i va B lE
This note receivable is denominated in US$ and bears interest at a rate of
5.3 percent per annum. Equal payments of principal and interest are payable
quarterly, with final payment due January 2, 2017. The current and long-term
partnership Contribution receivable shown in the Consolidated Balance
Sheets represent Cenovus’s 50 percent share of this promissory note, net of
payments to date.
M a n datO Ry R E C E i P t S
partnership Contribution receivable–US$
partnership Contribution receivable–C$ equivalent
Pa R t n E R Sh iP C O n tRiB Ut i O n Paya B lE
2011
348
346
2012
2013
2014
2015
Thereafter
total
366
364
386
384
407
405
429
427
569
565
2,505
2,491
This note payable is denominated in US$ and bears interest at a rate of
6.0 percent per annum. Equal payments of principal and interest are payable
quarterly, with final payment due January 2, 2017. The current and long-term
partnership Contribution payable amounts shown in the Consolidated Balance
Sheets represent Cenovus’s 50 percent share of this promissory note, net of
payments to date.
M a n datO Ry Pay M E n t S
partnership Contribution payable–US$
partnership Contribution payable–C$ equivalent
2011
345
343
2012
366
364
2013
388
386
2014
2015
Thereafter
total
412
410
437
435
584
581
2,532
2,519
In addition to the partnership Contribution receivable and payable, Other
Assets and Other Liabilities include equal amounts for interest bearing
partner loans, with no fixed repayment terms, related to the funding of
refining operating and capital requirements. At December 31, 2010 these
amounts were $274 million (December 31, 2009–$183 million).
97 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
12 . InvEnt OrIEs
As at December 31,
product
Upstream – Oil Sands
refining and Marketing
parts and Supplies
2010
2009
80
779
21
880
84
772
19
875
As a result of a significant decline in commodity prices in the latter half
of 2008, Cenovus recorded a write-down of its product inventory by
$186 million from cost to net realizable value at December 31, 2008. product
turnover and the improvement in commodity prices has resulted in all of the
2008 write-down being reversed, $178 million in 2009 and $8 million in 2010.
The total amount of inventories recognized as an expense during the year
was $5,997 million (2009–$4,999 million; 2008–$9,322 million).
13. Pr OPErtY, PL Ant AnD E QuIPmEnt , nEt
As at December 31,
Upstream
refining and Marketing
Corporate and Eliminations
* Depreciation, depletion and amortization
2010
Accumulated
DD&A*
(12,495)
(695)
(300)
Cost
22,691
5,883
446
29,020
(13,490)
net
10,196
5,188
146
15,530
2009
Accumulated
DD&A*
(11,455)
(534)
(274)
(12,263)
Cost
21,550
5,537
390
27,477
Net
10,095
5,003
116
15,214
Upstream property, plant and equipment includes internal costs directly
related to exploration, development and construction activities of
$102 million (2009–$117 million). Costs classified as general and administrative
expenses have not been capitalized as part of the capital expenditures.
Costs in respect of significant unproved properties and major development
projects are excluded from the country cost centre’s depletable base. refining
assets not put into use are excluded from depreciable costs. At the end of
the year these costs were:
As at December 31,
Upstream
refining and Marketing
2010
758
1,673
2,431
2009
644
1,366
2,010
2008
278
598
876
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 98
The Canadian prices used in the ceiling test evaluation of Cenovus’s crude oil and natural gas reserves at December 31, 2010 were:
WTI (US$/barrel)
AECO ($/Mcf)
Crude Oil ($/barrel)
Natural Gas Liquids ($/barrel)
Natural Gas ($/Mcf)
2011
85.00
4.25
64.75
62.19
4.05
2012
87.70
4.90
66.32
66.27
4.70
2013
90.50
5.40
65.08
68.94
5.20
2014
93.40
5.90
66.59
71.25
5.70
Average Annual
% Change
to 2022
2015
96.30
6.35
68.71
73.58
6.14
2%
4%
2%
2%
4%
During the year ended December 31, 2010, it was determined that a processing
unit at the Borger refinery was a redundant asset and would not be used in
future operations at the refinery. The fair value of the unit was determined
to be negligible based on market prices for refining assets of similar age and
condition. Accordingly, the carrying amount of the unit was reduced to zero and
an impairment loss of $37 million net to Cenovus, was recorded as additional
depreciation, depletion and amortization in the Consolidated Statements of
Earnings and Comprehensive Income within the refining and Marketing segment.
14. OtHEr AssEts
As at December 31,
partner Loans
Deferred Asset–refining and Marketing
Deferred pension plan and Savings plan
Other
15. LOnG- tErm DEB t
As at December 31,
Canadian Dollar Denominated Debt
revolving term debt*
U.S. Dollar Denominated Debt
revolving term debt*
Unsecured notes
Total Debt principal
Debt Discounts and Transaction Costs
Current portion of Long-Term Debt
2010
2009
274
99
11
7
391
183
121
9
7
320
Note
2010
2009
A
A
B
C
D
–
–
3,481
3,481
3,481
(49)
–
32
26
3,663
3,689
3,721
(65)
–
3,432
3,656
* revolving term debt includes commercial paper, bankers’ acceptances, LIBOr loans, prime rate loans and U.S. base rate loans.
The weighted average interest rate on outstanding debt for the year ended December 31, 2010 was 5.8 percent (2009–5.5 percent).
99 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVU S 20 10 ANNUAL rEpOr T
A) revolving Term Debt
At December 31, 2010, Cenovus had in place a committed credit facility in
the amount of C$2,500 million or its equivalent amount in U.S. dollars. The
committed credit facility matures on November 30, 2014 and is extendable
from time to time for a period of up to four years at the option of Cenovus
and upon agreement from the lenders. Borrowings are available by way
of Bankers Acceptances, LIBOr based loans, prime rate loans or U.S. base
rate loans. At December 31, 2010, no amounts were drawn on Cenovus’s
committed bank credit facility (2009–$58 million).
B) Unsecured Notes
In conjunction with the Arrangement, on September 18, 2009 Cenovus
completed a private offering of senior unsecured notes of an aggregate
principal amount of US$3,500 million. The notes were disclosed on Cenovus’s
Consolidated Balance Sheets as a long term liability, net of financing costs as
at September 30, 2009. The net proceeds of $3,718 million were placed into
an escrow account held by the escrow agent, The Bank of New York Mellon,
pending the completion of the Arrangement. Cenovus placed an additional
$162 million into the escrow account so that the total escrowed funds of
$3,880 million would be sufficient to pay the special mandatory redemption
price for the notes if the Arrangement did not proceed. Upon completion
of the Arrangement, funds were released from escrow and the proceeds of
the notes were used to pay the note payable to Encana of US$3,500 million
as part of the Arrangement. On November 30, 2009 these notes became the
direct, unsecured obligations of Cenovus. In 2010, substantially all of these
notes were exchanged for notes registered under the Securities Act of 1933
with the same terms and conditions as the original issued notes.
4.50% due September 15, 2014
5.70% due October 15, 2019
6.75% due November 15, 2039
us$ Principal
Amount
800
1,300
1,400
3,500
2010
796
1,293
1,392
3,481
2009
837
1,361
1,465
3,663
Cenovus has in place a Canadian base shelf prospectus for unsecured medium
term notes in the amount of $1,500 million. The Canadian shelf prospectus
allows for the issuance of medium term notes in Canadian dollars or other
foreign currencies from time to time in one or more offerings. The terms of
the notes, including, but not limited to, interest at either fixed or floating
rates and expiry dates, will be determined at the date of issue. At December
31, 2010, no medium term notes have been issued under this Canadian
prospectus. The shelf prospectus expires in July 2012.
time in one or more offerings. The terms of the notes, including, but not
limited to, interest at either fixed or floating rates and expiry dates, will be
determined at the date of issue. At December 31, 2010, no notes have been
issued under this U.S. prospectus. The shelf prospectus expires in August 2012.
At December 31, 2010, the Company is in compliance with all of the terms of
its debt agreements.
C) Debt Discounts and Transaction Costs
Cenovus has in place a U.S. base shelf prospectus for unsecured notes in the
amount of US$1,500 million. The U.S. shelf prospectus allows for the issuance
of debt securities in U.S. dollars or other foreign currencies from time to
Long-term debt transaction costs and discounts are recorded within long-term
debt and are being amortized using the effective interest method. During 2010,
no transaction costs were recorded within long term debt (2009–$70 million).
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 100
D) Mandatory Debt payments
2011
2012
2013
2014
2015
Thereafter
As at December 31,
Asset retirement Obligation, Beginning of Year
Liabilities Incurred
Liabilities Settled
Liabilities Divested
Change in Estimated Future Cash Flows
Accretion Expense
Foreign Currency Translation
Asset retirement Obligation, End of Year
US$ principal
Amount
C$ principal
Amount
Total C$
Equivalent
–
–
–
800
–
2,700
3,500
–
–
–
–
–
–
–
–
–
–
796
–
2,685
3,481
2009
793
6
(38)
(10)
357
45
(6)
2010
1,147
44
(33)
(88)
69
75
(1)
1,213
1,147
16. AssEt rEtIrEmEn t OB L IGA
tIOn
The aggregate carrying amount of the obligation associated with the retirement of upstream oil and gas assets and refining facilities is as follows:
The total undiscounted amount of estimated cash flows required to settle
the obligation is $6,093 million (2009–$5,683 million), which has been
discounted using a weighted average credit-adjusted risk free rate of
6.09 percent (2009–6.23 percent). Most of these obligations are not expected
to be paid for several years, or decades, in the future and will be funded from
general resources at that time.
17. OtHEr LIABILItIEs
As at December 31,
partner Loans
Deferred revenue
Other
2010
2009
274
37
35
346
183
40
16
239
101 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
18. sHArE CAPIt AL
aUt h O Ri Z E d
Cenovus is authorized to issue an unlimited number of Common Shares, an unlimited number of First preferred Shares and an unlimited number of Second
preferred Shares.
i S S U E d a n d O U t S ta n d i n g
As at December 31,
Outstanding, Beginning of Year
Common Shares Issued pursuant to the Arrangement
Common Shares Issued under Stock Option plans
Outstanding, End of Year
To determine Cenovus’s share capital amount at the time of the Arrangement,
Encana’s stated capital immediately prior to the Arrangement was split based
on the relative fair market values of the Encana and Cenovus Common Shares
at the time of the initial exchange. Cenovus’s share capital amount was
deducted from Encana’s net investment with the remaining $6,055 million
reclassified as paid in Surplus.
At December 31, 2010, there were 26 million (2009–24 million) Common
Shares available for future issuance under stock option plans. There were no
preferred Shares outstanding as at December 31, 2010.
The Company has a dividend reinvestment plan (“DrIp”). Under the DrIp,
holders of Common Shares may reinvest all or a portion of the cash dividends
payable on their Common Shares in additional Common Shares. At the
discretion of the Company, the additional Common Shares may be issued
from treasury or purchased on the market.
n E t i n v E S t M E n t
For periods prior to the Arrangement, Encana’s net investment in the
operations of Cenovus is presented as total Net Investment in the
Consolidated Financial Statements. Total Net Investment consists of Owner’s
Net Investment and AOCI.
2010
2009
number of
Common
shares
(thousands)
Amount
751,309
3,681
–
1,366
–
35
752,675
3,716
Number of
Common
Shares
(thousands)
–
751,273
36
751,309
Amount
–
3,680
1
3,681
S tO C k- B a S Ed C O M P En S at iO n
A) Employee Stock Option plan
Cenovus has an Employee Stock Option plan that provides employees with
the opportunity to exercise an option to purchase Common Shares of the
Company. Option exercise prices approximate the market price for the
Common Shares on the date the options were issued. Options granted are
exercisable at 30 percent of the number granted after one year, an additional
30 percent of the number granted after two years, and are fully exercisable after
three years. Options granted prior to February 17, 2010 expire after five years
while options granted on February 17, 2010 or later expire after seven years.
All options issued by the Company under the Employee Stock Option plan have
associated tandem stock appreciation rights. In lieu of exercising the options,
the tandem stock appreciation rights give the option holder the right to receive
a cash payment equal to the excess of the market price of Cenovus’s Common
Shares at the time of exercise over the exercise price of the right. The tandem
stock appreciation rights vest and expire under the same terms and conditions
as the underlying options. For the purpose of this note, options with associated
tandem stock appreciation rights are referred to as “TSArs”.
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 102
In addition, certain of the TSArs are performance based (“performance
TSArs”). The performance TSArs vest and expire under the same terms and
service conditions as the underlying option, and have an additional vesting
requirement whereby vesting is subject to achievement of prescribed
performance relative to pre-determined key measures. performance TSArs
that do not vest when eligible are forfeited.
In accordance with the Arrangement described in Note 2, each Cenovus and
Encana employee exchanged their original Encana TSAr for one Cenovus
replacement TSAr and one Encana replacement TSAr. The terms and
conditions of the Cenovus and Encana replacement TSArs are similar to the
terms and conditions of the original Encana TSAr. The original exercise price
of the Encana TSAr was apportioned to the Cenovus and Encana replacement
TSArs based on the one day volume weighted average trading price of
Cenovus’s Common Share price relative to that of Encana’s Common Share price
on the TSX on December 2, 2009. Cenovus TSArs and Cenovus replacement
TSArs are measured against the Cenovus Common Share price while Encana
replacement TSArs are measured against the Encana Common Share price. The
Cenovus replacement TSArs have similar vesting provisions as outlined above
for the Employee Stock Option plan. The original Encana performance TSArs
were also exchanged under the same terms as the original Encana TSArs.
Unless otherwise indicated, all references to TSArs collectively refer to both
the Cenovus issued TSArs and Cenovus replacement TSArs.
TSArs Held by Cenovus Employees
The following tables summarize the information related to the TSArs held by Cenovus employees as at December 31, 2010:
As at December 31, 2010,
(thousands of units)
Outstanding, Beginning of Year
Granted
Exercised for cash payment
Exercised as options for shares
Forfeited
Outstanding, End of Year
Exercisable, End of Year
Performance
tsArs
tsArs
Weighted
Average
Exercise
Price ($)
total
8,402
6,087
(1,099)
(948)
(398)
12,044
4,154
8,053
–
(77)
(109)
(794)
7,073
3,580
16,455
6,087
(1,176)
(1,057)
(1,192)
19,117
7,734
27.52
26.54
21.32
23.52
28.55
27.75
28.07
(thousands of units)
Outstanding tsArs
Exercisable tsArs
range of
Exercise price ($)
20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
35.00 to 39.99
40.00 to 44.99
45.00 to 49.99
Weighted
remaining
Contractual
total Life (Years)
Average Weighted
Average
Exercise
Price ($)
Performance
tsArs
tsArs
1,198
8,925
1,733
119
67
2
–
4,694
2,379
–
–
–
1,198
13,619
4,112
119
67
2
12,044
7,073
19,117
0.25
3.99
2.19
2.44
2.45
2.39
3.35
22.96
26.47
32.87
37.22
43.23
45.56
27.75
Performance
tsArs
tsArs
Weighted
Average
Exercise
Price ($)
total
1,172
1,818
1,051
72
40
1
–
2,351
1,229
–
–
–
1,172
4,169
2,280
72
40
1
4,154
3,580
7,734
22.94
26.59
32.86
37.22
43.23
45.56
28.07
103 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
Cenovus replacement TSArs Held by Encana Employees
Encana is required to reimburse Cenovus in respect of cash payments made
by Cenovus to Encana’s employees when these employees exercise a Cenovus
replacement TSAr for cash. No compensation expense is recognized and no
further Cenovus replacement TSArs will be granted to Encana employees.
Cenovus has recorded a liability of $123 million (2009–$84 million) in the
Consolidated Balance Sheets for Cenovus replacement TSArs held by
Encana employees using the fair value method, with an offsetting accounts
receivable from Encana. The fair value of each Cenovus replacement TSAr
held by Encana employees was estimated using the Black-Scholes-Merton
model with weighted average assumptions as follows:
risk Free rate
Dividend Yield
Volatility
Cenovus’s Common Share price
The following tables summarize information related to the Cenovus replacement TSArs held by Encana employees as at December 31, 2010:
2010
1.70%
2.40%
23.99%
$33.28
As at December 31, 2010,
(thousands of units)
Outstanding, Beginning of Year
Exercised for cash payment
Exercised as options for shares
Forfeited
Outstanding, End of Year
Exercisable, End of Year
Performance
tsArs
tsArs
Weighted
Average
Exercise
Price ($)
total
12,482
(3,847)
(105)
(316)
8,214
5,977
10,463
22,945
(411)
(1)
(1,111)
(4,258)
(106)
(1,427)
8,940
17,154
4,828
10,805
27.14
22.67
19.44
28.80
28.16
27.88
(thousands of units)
Outstanding tsArs
Exercisable tsArs
range of
Exercise price ($)
20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
35.00 to 39.99
40.00 to 44.99
45.00 to 49.99
Performance
tsArs
tsArs
Weighted
remaining
Contractual
total Life (Years)
Average Weighted
Average
Exercise
Price ($)
1,658
4,116
2,271
90
77
2
–
6,107
2,833
–
–
–
1,658
10,223
5,104
90
77
2
8,214
8,940
17,154
0.17
2.19
2.09
2.44
2.44
2.39
1.97
22.95
26.49
32.83
37.24
42.81
45.56
28.16
Performance
tsArs
tsArs
Weighted
Average
Exercise
Price ($)
total
1,650
2,711
1,515
54
46
1
–
3,368
1,460
–
–
–
1,650
6,079
2,975
54
46
1
5,977
4,828
10,805
22.95
26.63
32.74
37.24
42.81
45.56
27.88
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 104
Encana replacement TSArs Held by Cenovus Employees
Cenovus is required to reimburse Encana in respect of cash payments made
by Encana to Cenovus employees when a Cenovus employee exercises an
Encana replacement TSAr for cash. No further Encana replacement TSArs
will be granted to Cenovus employees.
The Company has recorded a liability of $24 million (2009–$70 million) in
the Consolidated Balance Sheets for Encana replacement TSArs held by
Cenovus’s employees using the fair value method.
The fair value of each Encana replacement TSAr was estimated using the Black-Scholes-Merton model with weighted average assumptions as follows:
risk Free rate
Dividend Yield
Volatility
Encana’s Common Share price
The following tables summarize information related to the Encana replacement TSArs held by Cenovus employees as at December 31, 2010:
2010
1.70%
2.74%
23.57%
$29.09
As at December 31, 2010,
(thousands of units)
Outstanding, Beginning of Year
Exercised for cash payment
Exercised as options for Encana shares
Forfeited
Outstanding, End of Year
Exercisable, End of Year
Performance
tsArs
tsArs
Weighted
Average
Exercise
Price ($)
total
8,305
(1,568)
(94)
(214)
6,429
4,461
8,052
(148)
–
16,357
(1,716)
(94)
(806)
(1,020)
7,098
3,605
13,527
8,066
30.46
24.43
21.47
31.98
31.17
30.85
(thousands of units)
Outstanding tsArs
Exercisable tsArs
range of
Exercise price ($)
Performance
tsArs
tsArs
Weighted
remaining
Contractual
total Life (Years)
Average Weighted
Average
Exercise
Price ($)
20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
35.00 to 39.99
40.00 to 44.99
45.00 to 49.99
50.00 to 54.99
7
4,371
312
1,597
74
66
2
–
4,718
–
2,380
–
–
–
7
9,089
312
3,977
74
66
2
6,429
7,098
13,527
2.75
2.04
1.75
2.13
2.49
2.46
2.39
2.06
23.04
28.59
32.61
36.47
42.28
47.86
50.39
31.17
Performance
tsArs
tsArs
Weighted
Average
Exercise
Price ($)
total
4
3,127
274
971
45
39
1
–
2,376
–
1,229
–
–
–
4
5,503
274
2,200
45
39
1
4,461
3,605
8,066
23.06
28.30
32.71
36.47
42.28
47.86
50.39
30.85
105 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
B) performance Share Units
The Company has granted performance Share Units (“pSUs”) to certain
employees under its performance Share Unit plan for Employees. pSUs are
whole share units and entitle employees to receive, upon vesting, either
a Common Share of Cenovus or a cash payment equal to the value of
a Cenovus Common Share. The number of pSUs eligible for payment is
determined over three years based on the units granted multiplied by
30 percent after year one, 30 percent after year two and 40 percent after year
three, multiplied by a performance multiplier for each year. The multiplier is
based on the Company achieving key pre-determined performance measures.
pSUs vest after three years.
The following table summarizes information related to the pSUs held by Cenovus employees as at December 31, 2010:
(thousands)
Outstanding, Beginning of Year
Granted
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
C) Deferred Share Units
Outstanding
Psus
–
1,252
(35)
35
1,252
Under two Deferred Share Unit plans, Cenovus directors, officers and
employees may receive Deferred Share Units (“DSUs”), which are equivalent
in value to a Common Share of the Company. Employees have the option to
convert either 25 or 50 percent of their annual bonus award into DSUs. DSUs
vest immediately, are redeemed in accordance with terms of the agreement
and expire on December 15 of the calendar year following the year of
cessation of directorship or employment.
pursuant to the terms of the Arrangement, Encana DSUs credited to directors,
officers and employees of Cenovus were exchanged for Cenovus DSUs. The
fair value of the Cenovus DSUs credited to each holder was based on the fair
market value of Cenovus Common Shares relative to Encana Common Shares
prior to the effective date of the Arrangement.
The following table summarizes information related to the DSUs held by Cenovus directors, officers and employees as at December 31, 2010:
(thousands)
Outstanding, Beginning of Year
Granted
Granted from Annual Bonus Awards
Units in Lieu of Dividends
Outstanding, End of Year
D) Stock-Based Compensation Expense (recovery)
Outstanding
Dsus
768
65
81
26
940
The following table summarizes the stock-based compensation expense (recovery) recorded for all plans within operating and general and administrative
expenses on the Consolidated Statements of Earnings and Comprehensive Income:
TSArs held by Cenovus employees
Encana replacement TSArs held by Cenovus employees
performance Share Units
Deferred Share Units
Total stock-based compensation expense (recovery)
* 2009 represents one month of compensation expense incurred under the Cenovus plan post Arrangement.
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 106
2010
2009*
2008
52
(23)
13
9
51
(2)
32
–
–
30
–
–
–
–
–
Included in the financial information prior to the Arrangement, the Company recorded compensation expense (recovery) for the following Encana plans:
Encana TSArs
Encana DSUs
Total stock-based compensation expense (recovery)
2010
2009
2008
–
–
–
4
3
7
(5)
1
(4)
19. CAPIt AL struCtu rE
Cenovus’s capital structure is comprised of Shareholders’ Equity plus Debt.
Cenovus’s objectives when managing its capital structure are to maintain
financial flexibility, preserve access to capital markets, ensure its ability to finance
internally generated growth and to fund potential acquisitions while maintaining
the ability to meet the Company’s financial obligations as they come due.
Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation
and Amortization (“EBITDA”). These metrics are used to steward Cenovus’s
overall debt position as measures of Cenovus’s overall financial strength. Debt is
defined as the current and long-term portions of long-term debt excluding any
amounts with respect to the partnership Contribution payable or receivable.
Cenovus monitors its capital structure and short-term financing requirements
using, among other things, non-GAAp financial metrics consisting of Debt to
Cenovus targets a Debt to Capitalization ratio of between 30 and 40 percent.
As at December 31,
Debt
Shareholders’ Equity
Total Capitalization
Debt to Capitalization ratio
Cenovus targets a Debt to Adjusted EBITDA of between 1.0 and 2.0 times.
As at December 31,
Debt
Net Earnings
Add (deduct):
Interest, net
Income tax expense
Depreciation, depletion and amortization
Accretion of asset retirement obligation
Foreign exchange (gain) loss, net
(Gain) loss on divestiture of assets
Other (income) loss, net
Adjusted EBITDA
Debt to Adjusted EBItDA
2010
3,432
10,022
13,454
26%
2009
3,656
818
244
344
1,527
45
304
–
(2)
3,280
1.1x
2009
3,656
9,608
13,264
28%
2008
3,719
2,526
233
774
1,397
40
(308)
–
3
4,665
0.8x
2010
3,432
993
279
170
1,310
75
(51)
9
(13)
2,772
1.2x
107 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
It is Cenovus’s intention to maintain an investment grade rating to ensure it
has continuous access to capital and the financial flexibility to fund its capital
programs, meet its financial obligations and finance potential acquisitions.
Cenovus will maintain a high level of capital discipline and manage its capital
structure to ensure sufficient liquidity through all stages of the economic
cycle. To manage the capital structure, Cenovus may adjust capital and
operating spending, adjust dividends paid to shareholders, purchase shares
for cancellation pursuant to normal course issuer bids, issue new shares, issue
new debt, draw down on its credit facilities or repay existing debt.
Cenovus’s capital structure, objectives and targets have remained unchanged
since Cenovus’s inception. At December 31, 2010, Cenovus is in compliance
with all of the terms of its debt agreements.
20. PEnsIOns AnD O tHEr P O st- EmPLOYmEn t BEnEFIts
The Company provides employees with a pension plan that includes defined
contribution and defined benefit components, and other post-employment
benefit plans (“OpEB”). Most of the employees participate in the defined
contribution pension; the defined benefit pension component is closed to
new entrants.
The Company files an actuarial valuation of its pension plans with the
provincial regulator at least every three years. The most recently filed
valuation was dated November 30, 2009 and the next required actuarial
valuation will be as at December 31, 2012.
Information related to defined benefit pension and OpEB plans, based on actuarial estimations is as follows:
As at December 31,
Accrued Benefit Obligation, End of Year
Fair Value of plan Assets, End of Year
Funded Status–plan Assets (less) than Benefit Obligation
Amounts Not recognized:
Unamortized net actuarial (gain) loss
Unamortized past service cost
Accrued Benefit Asset (Liability)
The weighted average assumptions used to determine benefit obligations are as follows:
As at December 31,
Discount rate
rate of Compensation Increase
Estimated future payment of pension and other benefits are as follows:
2011
2012
2013
2014
2015
2016 – 2020
Total
pension Benefits
OpEB
2010
2009
2010
2009
68
59
(9)
20
–
11
56
54
(2)
15
–
13
14
–
(14)
1
–
(13)
11
–
(11)
(1)
1
(11)
pension Benefits
2010
2009
5.25%
4.05%
6.00%
4.05%
OpEB
2010
5.25%
5.65%
2009
6.00%
5.77%
pension Benefits
OpEB
1
2
2
3
4
23
35
–
–
1
1
1
9
12
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 108
21. FInAnCIAL Instru mEn ts AnD rIsk mAnAGEmEn t
Cenovus’s consolidated financial assets and liabilities consist of cash and cash
equivalents, accounts receivable and accrued revenues, accounts payable
and accrued liabilities, partnership Contribution receivable and payable and
partner loans, risk management assets and liabilities, and long-term debt.
risk management assets and liabilities arise from the use of derivative
financial instruments. Fair values of financial assets and liabilities, summarized
information related to risk management positions, and discussion of risks
associated with financial assets and liabilities are presented as follows.
risk management assets and liabilities are recorded at their estimated fair
value based on mark-to-market accounting, using quoted market prices or,
in their absence, third-party market indications and forecasts.
Long-term debt is carried at amortized cost. The estimated fair values of
long-term borrowings have been determined based on market information. At
December 31, 2010, the carrying value of Cenovus’s long-term debt accounted
for using amortized cost was $3,432 million and the fair value was $3,940 million
(December 31, 2009–carrying value–$3,656 million, fair value–$3,964 million).
A) Fair Value of Financial Assets and Liabilities
B) risk Management Assets and Liabilities
The fair values of cash and cash equivalents, accounts receivable and accrued
revenues, and accounts payable and accrued liabilities approximate their
carrying amount due to the short-term maturity of those instruments.
The fair values of the partnership Contribution receivable and partnership
Contribution payable and partner loans approximate their carrying amount
due to the specific non-tradeable nature of these instruments.
Under the terms of the Arrangement with Encana, the risk management
positions at November 30, 2009 were allocated to Cenovus based upon
Cenovus’s proportion of the related volumes covered by the contracts. To
effect the allocation, Cenovus entered into a contract with Encana with the
same terms and conditions as between Encana and the third parties to the
existing contracts. All positions entered into after the Arrangement have been
negotiated between Cenovus and third parties.
Net risk Management position
As at December 31,
risk Management
Current asset
Long-term asset
risk Management
Current liability
Long-term liability
Net risk Management Asset (Liability)
2010
2009
163
43
206
163
10
173
33
60
1
61
70
4
74
(13)
Of the $33 million net risk management asset balance at December 31, 2010, an asset of $41 million relates to the contract with Encana (2009–net liability of $15 million).
Summary of Unrealized risk Management positions
As at December 31,
Commodity prices
Crude Oil
Natural Gas
power
Total Fair Value
2010
risk management
2009
risk Management
Asset
Liability
net
Asset
Liability
Net
4
202
–
206
159
–
14
173
(155)
202
(14)
33
8
53
–
61
66
–
8
74
(58)
53
(8)
(13)
109 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
Net Fair Value Methodologies Used to Calculate Unrealized risk Management positions
As at December 31,
prices actively quoted
prices sourced from observable data or market corroboration
Total Fair Value
2010
2009
40
(7)
33
6
(19)
(13)
prices actively quoted refers to the fair value of contracts valued using quoted prices in an active market. prices sourced from observable data or market
corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.
Net Fair Value of Commodity price positions at December 31, 2010
As at December 31, 2010,
Crude Oil Contracts
Fixed price Contracts
WTI NYMEX Fixed price
WTI NYMEX Fixed price
WTI NYMEX Fixed price
WTI NYMEX Fixed price
Other Fixed price Contracts *
Other Financial positions **
Crude Oil Fair Value position
natural Gas Contracts
Fixed price Contracts
NYMEX Fixed price
NYMEX Fixed price
AECO Fixed price
Other Fixed price Contracts *
Natural Gas Fair Value position
Power Purchase Contracts
power Fair Value position
Notional
Volumes
Term
Average
price
Fair
value
28,600 bbls/d
29,200 bbls/d
5,000 bbls/d
3,000 bbls/d
2011
2011
2012
2012
2011
US$85.54/bbl
C$88.32/bbl
US$92.44/bbl
C$93.82/bbl
379 MMcf/d
130 MMcf/d
80 MMcf/d
2011
2012
2012
US$5.70/Mcf
US$5.96/Mcf
C$4.49/Mcf
2011-2013
(85)
(58)
(3)
(1)
4
(12)
(155)
158
41
–
3
202
(14)
* Cenovus has entered into fixed priced swaps to protect against widening price differentials between production areas in Canada and various sales points.
** Other financial positions are part of ongoing operations to market the Company’s production.
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 110
Earnings Impact of realized and Unrealized Gains (Losses) on risk Management positions
For the years ended December 31,
Gross revenues
Less: royalties
Net revenues
Operating Expenses and Other
Gain (Loss) on risk Management
For the years ended December 31,
Gross revenues
Less: royalties
Net revenues
Operating Expenses and Other
Gain (Loss) on risk Management
reconciliation of Unrealized risk Management positions
For the years ended December 31,
Fair Value of Contracts, Beginning of Year
Change in Fair Value of Contracts in place at Beginning of Year
and Contracts Entered into During the Year
Fair Value of Contracts realized During the Year
Fair Value of Contracts, End of Year
Commodity price Sensitivities – risk Management positions
realized Gain (Loss)
2010
2009
2008
272
–
272
6
278
1,154
–
1,154
(38)
1,116
(305)
–
(305)
31
(274)
Unrealized Gain (Loss)
2010
2009
2008
60
–
60
(14)
46
(668)
–
(668)
(30)
(698)
890
–
890
9
899
2010
total
unrealized
Gain (Loss)
2009
2008
Total
Unrealized
Gain (Loss)
Total
Unrealized
Gain (Loss)
324
(278)
46
418
(1,116)
(698)
625
274
899
Fair
value
(13)
324
(278)
33
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables
held constant. When assessing the potential impact of these commodity price changes, Management believes 10 percent volatility is a reasonable measure.
Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting earnings before income tax at December 31, 2010 as follows:
Crude oil price
Natural gas price
power price
10% Price
Increase
10% Price
Decrease
(227)
(104)
6
227
104
(6)
111 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
C) risks Associated with Financial Assets and Liabilities
Commodity Price Risk
Commodity price risk arises from the effect that fluctuations of future
commodity prices may have on the fair value or future cash flows of financial
assets and liabilities. To partially mitigate exposure to commodity price risk,
the Company has entered into various financial derivative instruments. The
use of these derivative instruments is governed under formal policies and is
subject to limits established by the Board of Directors. The Company’s policy
is not to use derivative financial instruments for speculative purposes.
Crude Oil – The Company has partially mitigated its exposure to the
commodity price risk on its crude oil sales and condensate supply used for
blending with fixed price swaps. To help protect against widening crude oil
price differentials in various production areas, Cenovus has entered into a
limited number of swaps to manage the price differentials between these
production areas and various sales points.
Natural Gas – To partially mitigate the natural gas commodity price risk, the
Company has entered into swaps, which fix the NYMEX and AECO prices. To
help protect against widening natural gas price differentials in various production
areas, Cenovus has entered into a limited number of swaps to manage the price
differentials between these production areas and various sales points.
power – The Company has in place two Canadian dollar denominated
derivative contracts, which commenced January 1, 2007 for a period of 11
years, to manage its electricity consumption costs.
Credit Risk
Credit risk arises from the potential that the Company may incur a loss
if a counterparty to a financial instrument fails to meet its obligation
in accordance with agreed terms. This credit risk exposure is mitigated
through the use of Board-approved credit policies governing the Company’s
credit portfolio and with credit practices that limit transactions according
to counterparties’ credit quality. Agreements are entered into with
major financial institutions with investment grade credit ratings or with
counterparties having investment grade credit ratings. A substantial portion of
Cash outflows relating to financial liabilities are outlined in the table below:
Cenovus’s accounts receivable are with customers in the oil and gas industry
and are subject to normal industry credit risks. As at December 31, 2010, over
92 percent (2009–98 percent) of Cenovus’s accounts receivable and financial
derivative credit exposures are with investment grade counterparties.
At December 31, 2010, Cenovus had two counterparties whose net
settlement position individually account for more than 10 percent (2009–
three counterparties, including Encana) of the fair value of the outstanding
in-the-money net financial and physical contracts by counterparty. The
maximum credit risk exposure associated with accounts receivable and
accrued revenues, risk management assets and the partnership Contribution
receivable and the partner loans receivable is the total carrying value.
The current concentration of this credit risk resides with A rated or higher
counterparties. Cenovus’s exposure to its counterparties is acceptable and
within Credit policy tolerances.
liquidity Risk
Liquidity risk is the risk that Cenovus will not be able to meet all of its
financial obligations as they become due. Liquidity risk also includes the risk
of not being able to liquidate assets in a timely manner at a reasonable price.
Cenovus manages its liquidity risk through the active management of cash
and debt. As disclosed in Note 19, Cenovus targets a Debt to Capitalization
ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of between
1.0 to 2.0 times to manage the Company’s overall debt position. It is
Cenovus’s intention to maintain investment grade credit ratings on its senior
unsecured debt.
Cenovus manages its liquidity risk by ensuring that it has access to multiple
sources of capital including: cash and cash equivalents, cash from operating
activities, undrawn credit facilities, commercial paper and availability
under its shelf prospectuses. At December 31, 2010, Cenovus’s committed
credit facility was fully available. In addition Cenovus had $1,500 million in
unused capacity under its Canadian shelf prospectus and US$1,500 million in
unused capacity under its U.S. shelf prospectus, the availability of which are
dependent on market conditions.
Accounts payable and Accrued Liabilities
risk Management Liabilities
Long-Term Debt (1) (2)
partnership Contribution payable (1)
partner Loans payable
(1) principal and interest, including current portion
(2) No principal repayment until 2014 and thereafter (see Note 15D)
Less than 1 Year
1 - 3 Years
4 - 5 Years
Thereafter
1,825
163
203
486
–
–
10
407
972
274
–
–
1,167
972
–
–
–
5,236
609
–
total
1,825
173
7,013
3,039
274
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 112
Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that
may affect the fair value or future cash flows of Cenovus’s financial assets
or liabilities. As Cenovus operates in North America, fluctuations in the
exchange rate between the U.S./Canadian dollars can have a significant effect
on reported results. Cenovus’s functional currency and reporting currency
is Canadian dollars. All amounts are reported in Canadian dollars, unless
otherwise indicated.
As disclosed in Note 9, Cenovus’s foreign exchange (gain) loss primarily
includes unrealized foreign exchange gains and losses on the translation of
the U.S. dollar debt issued from Canada and the translation of the U.S. dollar
partnership Contribution receivable issued from Canada. At December 31,
2010, Cenovus had US$3,500 million in U.S. dollar debt issued from Canada
(US$3,525 million at December 31, 2009) and US$2,505 million related to
the U.S. dollar partnership Contribution receivable (US$2,834 million at
December 31, 2009). A $0.01 change in the U.S. to Canadian dollar exchange
rate would have resulted in a $10 million change in foreign exchange (gain)
loss at December 31, 2010 (2009–$7 million).
interest Rate Risk
Interest rate risk arises from changes in market interest rates that may affect
the earnings, cash flows and valuations. Cenovus has the flexibility to partially
mitigate its exposure to interest rate changes by maintaining a mix of both
fixed and floating rate debt.
At December 31, 2010, one hundred percent of the Company’s debt was fixed-
rate debt and as a result, had interest rates on floating rate debt changed
by one percent there would be no impact on net earnings (December 31,
2009–$nil; 2008–$5 million). This assumes the amount of fixed and floating
debt remains unchanged from December 31, 2010.
22 . s uPPLEmEnt Ar Y InFOr mA tIOn
A) per Share Amounts
For the years ended December 31, (millions)
Weighted Average Common Shares Outstanding – Basic
Effect of Stock Options and Other Dilutive Securities
Weighted Average Common Shares Outstanding – Diluted
2010
751.9
0.8
752.7
2009
751.0
0.4
751.4
Since Cenovus’s shares were issued pursuant to the Arrangement, the per share amounts disclosed for 2009 and 2008 are based on the number of Encana’s
Common Shares outstanding.
B) Supplementary Cash Flow Information
For the years ended December 31,
Interest paid
Income Taxes paid
2010
423
62
2009
426
1,284
Income taxes paid in 2009 includes amounts paid to Encana as a result of the dissolution of a partnership in connection with the Arrangement.
2008
750.1
1.7
751.8
2008
422
542
113 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
23. COmmItmEnts AnD COn tInGEnC IEs
A) Commitments
As part of normal operations, the Company has committed to certain amounts over the next five years and thereafter as follows:
2011
2012
2013
2014
2015
Thereafter
Total
Operating Leases (Building Leases)
pipeline Transportation (1)
purchases of Goods and Services
Capital Commitments
product purchases
Other Long-Term Commitments
Total payments
product Sales
33
107
157
91
23
4
415
50
(1) Certain transportation commitments included are subject to regulatory approval
At December 31, 2010, there were outstanding letters of credit aggregating
$23 million issued as security for performance under certain contracts
(2009–$13 million).
In addition to the above, Cenovus’s commitments related to its risk
management program are disclosed in Note 21.
B) Contingencies
legal Proceedings
Cenovus is involved in various legal claims associated with the normal course
of operations. Cenovus believes it has made adequate provisions for such
legal claims.
85
167
10
4
18
1
285
56
78
166
7
4
18
–
273
57
1,553
953
23
14
7
1
2,551
63
1,924
1,653
232
188
102
9
4,108
332
87
93
23
71
18
2
294
52
88
167
12
4
18
1
290
54
asset Retirement
Cenovus is responsible for the retirement of long-lived assets related to its
oil and gas properties, refining facilities and midstream facilities at the end of
their useful lives. Cenovus has recognized a liability of $1,218 million, including
$5 million that has been classified as Liabilities related to Assets Held for
Sale, based on current legislation and estimated costs. Actual costs may differ
from those estimated due to changes in legislation and changes in costs.
income tax Matters
The tax regulations and legislation and interpretations thereof in the various
jurisdictions in which Cenovus operates are continually changing. As a result,
there are usually a number of tax matters under review. Management believes
that the provision for taxes is adequate.
24. unItED st AtEs ACCOun tInG PrInCI PLEs AnD rE P OrtInG
The Cenovus Consolidated Financial Statements have been prepared
in accordance with accounting principles generally accepted in Canada
(“Canadian GAAp”) which, in most respects, conform to accounting
principles generally accepted in the United States (“U.S. GAAp”). The
significant differences between Canadian GAAp and U.S. GAAp applicable to
Cenovus are described in this note. The most notable differences are:
• full cost accounting;
• pensions and other post-employment benefits;
• liability-based stock compensation plans;
• income taxes;
• other comprehensive income; and
• joint venture accounting.
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 114
R E C O n C i l i at i O n O F n E t E a R n i n g S U n d E R C a n a d i a n g a a P t O U . S . g a a P
For the years ended December 31,
Net Earnings–Canadian GAAp
Increase (Decrease) in Net Earnings Under U.S. GAAp:
Operating expense
Depreciation, depletion and amortization expense
General and administrative expense
Stock-based compensation expense
Income tax expense
Net Earnings–U.S. GAAp
Note 24
C ii)
A, C ii)
C ii)
D
C O n S O l i dat E d S tat E M E n t S O F E a R n i n g S a n d C O M P R E h E n S i v E i n C O M E – U . S . g a a P
For the years ended December 31,
Note 24
Gross revenues
Less: royalties
Net revenues
Expenses
production and mineral taxes
Transportation and blending
Operating
purchased product
Depreciation, depletion and amortization
General and Administrative
Interest, net
Accretion of asset retirement obligation
Foreign exchange (gain) loss, net
Stock-based compensation–options
(Gain) loss on divestiture of assets
Other (income) loss, net
Earnings Before Income Tax
Income tax expense
Net Earnings – U.S. GAAp
Other Comprehensive Income (Loss), Net of Tax
Foreign Currency Translation Adjustment
Compensation plans
Comprehensive Income
C ii)
A, C ii)
C ii)
D
2010
993
9
107
11
–
(87)
1,033
2010
13,422
449
12,973
34
1,065
1,293
7,549
1,203
240
279
75
(51)
–
9
(13)
11,683
1,290
257
1,033
(13)
(7)
1,013
2009
818
4
239
9
–
(199)
871
2009
11,790
273
11,517
44
760
1,308
5,910
1,288
202
244
45
304
–
–
(2)
10,103
1,414
543
871
(238)
32
665
2008
2,526
(13)
21
(17)
1
(138)
2,380
2008
18,103
533
17,570
80
1,021
1,305
10,341
1,376
188
233
40
(308)
(1)
–
3
14,278
3,292
912
2,380
347
(9)
2,718
115 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
C O n d E n S E d C O n S O l i dat E d B a l a n C E S h E E t S – U . S . g a a P
As at December 31,
Assets
Current Assets
Assets Held for Sale
2010
2009
Note 24
As reported
u.s. GAAP
As reported
U.S. GAAp
2,775
65
2,775
65
2,453
–
2,453
–
property, plant and Equipment
A, B, C ii)
(includes unproved properties and major development
projects of $2,428 and $2,010 as of December 31, 2010
and 2009, respectively)
Accumulated Depreciation, Depletion and Amortization
property, plant and Equipment, net
(Full Cost Method for Oil and Gas Activities)
partnership Contribution receivable
risk Management
Other Assets
Goodwill
Liabilities and Shareholders’ Equity
Current Liabilities
Liabilities related to Assets Held for Sale
Long-Term Debt
partnership Contribution payable
risk Management
Asset retirement Obligation
Other Liabilities
Deferred Income Taxes
Shareholders’ Equity
29,020
(13,490)
28,997
(14,045)
15,530
14,952
2,145
43
391
1,146
2,145
43
390
1,146
27,477
(12,263)
15,214
2,621
1
320
1,146
27,455
(12,925)
14,530
2,621
1
319
1,146
22,095
21,516
21,755
21,070
2,485
7
3,432
2,176
10
1,213
346
2,404
12,073
10,022
22,095
2,644
7
3,432
2,176
10
1,213
348
2,331
12,161
9,355
21,516
1,984
–
3,656
2,650
4
1,147
239
2,467
12,147
9,608
21,755
2,098
–
3,656
2,650
4
1,147
239
2,368
12,162
8,908
21,070
C i)
C i), C ii), D
C i), C ii)
D
E
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 116
C O n d E n S E d C O n S O l i dat E d S tat E M E n t S O F C a S h F lOW S – U . S . g a a P
For the years ended December 31,
Operating Activities
Net earnings
Depreciation, depletion and amortization
Deferred income taxes
Unrealized (gain) loss on risk management
Unrealized foreign exchange (gain) loss
Accretion of asset retirement obligation
(Gain) loss on divestiture of assets
Other (income) loss, net
Net change in other assets and liabilities
Net change in non-cash working capital
Cash From Operating Activities
Cash (Used in) Investing Activities
Net Cash provided before Financing Activities
Cash From (Used in) Financing Activities
n Ot E S
A) Full Cost Accounting
Under U.S. GAAp, a ceiling test is applied to ensure the unamortized
capitalized costs in a cost centre do not exceed the sum, net of applicable
income taxes, of the present value, discounted at 10 percent, of the estimated
future net revenues calculated on the basis of estimated value of future
production from proved reserves using oil and gas prices at the balance sheet
date, less related unescalated estimated future development and production
costs, plus unimpaired unproved property costs. For 2010 and 2009, depletion
charges under U.S. GAAp were also calculated by reference to proved reserves
estimated using an average price for the prior 12-month period. For 2008,
depletion charges under U.S. GAAp were calculated by reference to proved
reserves estimated using oil and gas prices at the balance sheet date.
Under Canadian GAAp, a similar ceiling test calculation is performed with the
exception that cash flows from proved reserves are undiscounted and utilize
forecast pricing and future development and production costs to determine
whether impairment exists. The impairment amount is measured using the
fair value of proved and probable reserves. Depletion charges under Canadian
GAAp are also calculated by reference to proved reserves estimated using
estimated future prices and costs.
At December 31, 2008, Cenovus’s capitalized costs of oil and gas properties
in Canada exceeded the full cost ceiling resulting in a non-cash U.S. GAAp
write-down of $73 million charged to DD&A. Additional depletion was also
recorded in certain prior years, as a result of ceiling test differences between
Canadian GAAp and U.S. GAAp. As a result, the depletion base of unamortized
capitalized costs is less for U.S. GAAp purposes.
2010
2009
2008
1,033
1,203
116
(46)
(69)
75
9
35
(55)
293
2,594
(1,796)
798
(631)
871
1,288
(396)
698
327
45
–
7
(26)
225
3,039
(2,063)
976
(977)
2,380
1,376
554
(899)
(317)
40
–
(20)
(92)
202
3,224
(2,109)
1,115
(1,226)
The U.S. GAAp adjustment for the difference in depletion calculations resulted
in a decrease to DD&A of $107 million (2009–$237 million; 2008–$98 million).
B) property, plant and Equipment Allocation
For periods prior to the Arrangement, net property, plant and equipment
related to Canadian upstream oil and gas activities have been allocated for
U.S. GAAp carve-out purposes using the same methodology as the carve-out
allocation for Canadian GAAp purposes.
The balances related to Canadian upstream operations have been allocated
between Cenovus and Encana in accordance with the CICA Handbook
Accounting Guideline AcG-16, based on the ratio of future net revenue,
discounted at 10 percent, of the properties carved out to the discounted
future net revenue of all proved properties in Canada using the reserve
reports dated December 31, 2008. Future net revenue is the estimated net
amount to be received with respect to development and production of
crude oil and natural gas reserves, the value of which has been determined by
independent qualified reserve evaluators.
C) Compensation plans
i) pensions and Other post-Employment Benefits
Under U.S. GAAp, ASC 715-30, “Compensation – retirement Benefits”, requires
Cenovus to recognize the over-funded or under-funded status of defined
benefit and post-employment plans on the balance sheet as an asset or
liability and to recognize changes in the funded status through Other
Comprehensive Income. Canadian GAAp does not require the recognition of
the funded status of these plans on its balance sheet.
117 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
ii) Liability-Based Stock Compensation plans
D) Income Taxes
Under Canadian GAAp, obligations for liability-based stock compensation
plans are recorded using the intrinsic-value method of accounting. For
U.S. GAAp purposes, Cenovus adopted ASC 718, “Compensation – Stock
Compensation” for the year ended December 31, 2006 using the modified-
prospective approach. Under ASC 718, liability-based stock compensation
plans, including tandem share appreciation rights, performance tandem
share appreciation rights, share appreciation rights and performance share
appreciation rights, are required to be re-measured at fair value at each
reporting period up until the settlement date.
To the extent compensation cost relates to employees directly involved
in crude oil and natural gas development activities, certain amounts are
capitalized to property, plant and equipment. Amounts not capitalized are
recognized as administrative expenses or operating expenses. The current
period adjustments have the following impact:
• Net property, plant and equipment decreased by $1 million (2009–
$25 million decrease)
• Current liabilities decreased by $14 million (2009–$41 million decrease)
• Other liabilities decreased by $7 million (2009–$1 million increase)
• Operating expenses decreased by $9 million (2009–$4 million decrease)
• Administrative expenses decreased by $11 million (2009–$9 million decrease)
• No adjustment was made to depreciation, depletion and amortization
expenses (2009–$2 million decrease)
U.S. GAAp uses enacted tax rates and legislative changes to calculate current
and deferred income taxes, whereas Canadian GAAp uses substantively
enacted tax rates and legislative changes. In 2009, Cenovus incurred losses
in one of its subsidiary companies which were recognized and included
in calculating future income taxes for Canadian GAAp purposes on the
basis that the tax legislative changes were substantially enacted. For U.S.
GAAp, these losses were not recognized as the tax legislative changes were
not enacted by December 31, 2009 nor December 31, 2010. There was no
additional impact to income tax expense in 2010 (2009–$131 million, 2008–
nil). In 2010 some of these losses were claimed to reduce the current taxes
payable under Canadian GAAp. For U.S. GAAp the losses were not available
and the current tax payable increased by $59 million offset by a decrease to
the deferred income tax payable with no impact on total tax expense.
The remaining differences resulted from the deferred income tax adjustments
included in the reconciliation of Net Earnings under Canadian GAAp to U.S.
GAAp and the Condensed Consolidated Balance Sheet include the effect of
such rate differences, if any, as well as the tax effect of the other reconciling
items noted.
The following table provides a reconciliation of the statutory rate to the actual tax rate:
For the years ended December 31,
Earnings Before Income Tax–U.S. GAAp
Canadian Statutory rate
Expected Income Tax
Effect on Taxes resulting from:
Statutory and other rate differences
Non-deductible stock-based compensation
Multi-jurisdictional financing
Foreign exchange gains not included in net earnings
Non-taxable capital (gains) losses
recognition of capital losses
Unrecognized non-capital losses
Other
Income Tax–U.S. GAAp
Effective Tax rate
2010
1,290
28.2%
364
(36)
32
(93)
28
(9)
(107)
–
78
257
19.9%
2009
1,414
29.2%
413
(7)
–
(134)
58
30
–
131
52
543
38.4%
2008
3,292
29.7%
977
(88)
–
(135)
71
(53)
–
–
140
912
27.7%
CENOVUS 201 0 A NNUA L rEpOr T · NOTES TO CON SOL IDATED FIN AN C I AL STATEMENTS · 118
The net deferred income tax liability consists of:
As at December 31,
Deferred Tax Liabilities
property, plant and equipment in excess of tax values
Timing of partnership items
Net foreign exchange gains
risk management
Other
Deferred Tax Assets
Unused tax losses
risk management
Other
Net Deferred Income Tax Liability
E) Other Comprehensive Income
2010
2009
2,390
2,407
125
127
55
55
(209)
(45)
(167)
2,331
9
–
17
79
(111)
(33)
–
2,368
ASC 715-30 requires a change in the funded status of defined benefit and
post-employment plans to be recognized on the balance sheet and changes
in the funded status through other comprehensive income. In 2010, a loss of
$7 million, net of tax was recognized in other comprehensive income (2009–
gain of $32 million) as noted in D i). On adoption of ASC 715-30, as required,
the transitional amount of $24 million, net of tax was booked directly to
Accumulated Other Comprehensive Income.
F) Joint Venture with Conocophillips
Under Canadian GAAp, the refining operations that are jointly controlled are
proportionately consolidated. U.S. GAAp requires the refining operations be
accounted for using the equity method. However, under an accommodation
of the U.S. Securities and Exchange Commission, accounting for jointly
controlled investments does not require reconciliation from Canadian to U.S.
GAAp if the joint venture is jointly controlled by all parties having an equity
interest in the entity, which is the case for the refining operations. Equity
accounting for the refining operations would have no impact on Cenovus’s
net earnings or retained earnings. As required, the following disclosures are
provided for the refining operations of the joint venture.
C O n S O l i dat E d S tat E M E n t S O F E a R n i n g S
For the years ended December 31,
Operating Cash Flow (See Note 1)
Depreciation, depletion and amortization
Other
Net Earnings (Loss)
C O n S O l i dat E d B a l a n C E S h E E t S
As at December 31,
Current Assets
Long-term Assets
Current Liabilities
Long-term Liabilities
C O n S O l i dat E d S tat E M E n t S O F C a S h F lOW S
For the years ended December 31,
Cash From (Used in) Operating Activities
Cash From (Used in) Investing Activities
2010
2009
67
(229)
(12)
(174)
2010
951
5,275
559
327
2010
117
(657)
358
(220)
(12)
126
2009
808
5,104
511
410
2009
(62)
(1,034)
119 · NOTES TO CONSOLIDATED FINANCIAL STATEMENTS · CENOVUS 20 10 ANNUAL rEpOr T
SUP PlEMEntal inFORMatiOn (UnaUd i tEd)
For the period ended December 31, 2010
Canadian Dollars/Canadian protocol
F I nAn C I A L s tAt I s t I C s
(C$ millions, except per share amounts)
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
2010
2009
Gross revenues
Less: royalties
Net revenues
Operating Cash Flow
Crude Oil and Natural Gas Liquids
Foster Creek and Christina Lake
pelican Lake
Conventional
Natural Gas
Other Upstream Operations
refining and Marketing
Operating Cash Flow
Cash Flow Information
Cash from Operating Activities
Deduct (Add back):
Net change in other assets and liabilities
Net change in non-cash working capital
Cash Flow (1)
per share – Basic
– Diluted
Operating Earnings (2)
per share – Diluted
Net Earnings
per share – Basic
– Diluted
Effective Tax rates using
Net Earnings
Operating Earnings, excluding divestitures
Canadian Statutory rate
Foreign Exchange rates (US$ per C$1)
Average
period end
13,422
449
3,280
108
3,222
107
3,318
123
3,602
111
11,790
273
3,103
98
3,080
79
2,871
53
2,736
43
12,973
3,172
3,115
3,195
3,491
11,517
3,005
3,001
2,818
2,693
765
287
751
1,081
16
2,900
75
2,975
195
58
175
253
6
687
125
812
179
71
191
246
–
687
(27)
660
176
71
163
268
7
685
(20)
665
215
87
222
314
3
841
(3)
838
663
302
753
2,061
42
3,821
368
4,189
232
84
203
412
10
941
13
954
198
98
218
500
22
1,036
98
162
75
199
555
4
995
178
1,134
1,173
71
45
133
594
6
849
79
928
2,594
658
645
471
820
3,039
150
1,414
793
682
(14)
24
(13)
149
(13)
(53)
(15)
114
648
0.86
0.86
140
0.19
73
0.10
0.10
509
0.68
0.68
159
0.21
223
0.30
0.30
537
0.71
0.71
142
0.19
172
0.23
0.23
721
0.96
0.96
353
0.47
525
0.70
0.70
(55)
234
2,415
3.21
3.21
794
1.06
993
1.32
1.32
14.6%
21.7%
28.2%
(26)
220
2,845
3.79
3.79
1,522
2.03
818
1.09
1.09
29.6%
25.0%
29.2%
(14)
(71)
235
0.31
0.31
169
0.23
42
0.06
0.06
(3)
493
924
1.23
1.23
427
0.57
101
0.13
0.13
(6)
(146)
945
1.26
1.26
512
0.68
160
0.21
0.21
(3)
(56)
741
0.99
0.99
414
0.55
515
0.69
0.69
0.971
1.005
0.987
1.005
0.962
0.971
0.973
0.943
0.961
0.985
0.876
0.956
0.947
0.956
0.911
0.933
0.857
0.860
0.803
0.794
(1) Cash Flow is a non-GAAp measure defined as Cash from Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the
Consolidated Statement of Cash Flows.
(2) Operating Earnings is a non-GAAp measure defined as Net Earnings excluding after tax gain/loss on discontinuance, after-tax gain on bargain purchase, after-tax effect of unrealized mark-to-market
accounting gains/losses on derivative instruments, after-tax gains/losses on translation of U.S. dollar denominated Notes issued from Canada, after-tax foreign exchange gains/losses on settlement of
intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates.
CENOVUS 201 0 A NNUA L rEpOr T · S Up pL EM E NTA L I N FOrMATI ON ( UN AUDITED) · 120
F I n A n C I A L s tAt I s t I C s ( C O n t I n u E D )
Financial metrics (non-GAAP measures)
Debt to Capitalization (1) (2)
Debt to Adjusted EBITDA (2) (3)
return on Capital Employed (4)
return on Common Equity (5)
2010
2009
26%
1.2x
9%
10%
28%
1.1x
8%
8%
(1) Capitalization is a non-GAAp measure defined as long-term debt including current portion plus Shareholders’ Equity.
(2) Debt is defined as the current and long-term portions of long-term debt.
(3) Adjusted EBITDA is a non-GAAp measure defined as adjusted earnings before interest, income taxes, DD&A, accretion of asset retirement obligations, foreign exchange gains (losses), gains (losses) on
divestiture of assets and other income (loss).
(4) Calculated, on a trailing twelve-month basis, as net earnings before after tax interest divided by average shareholder’s equity plus average debt, including current portion.
(5) Calculated, on a trailing twelve-month basis, as net earnings divided by average shareholder’s equity.
Common Share Information
Common Shares Outstanding (millions) (1)
period end
Average – Basic
Average – Diluted
price range ($ per share)
TSX – C$
High
Low
Close
NYSE – US$
High
Low
Close
Dividends paid ($ per share) (2)
Share Volume Traded (millions)
Year
Q4
2010
Q3
Q2
Q1
December
2009
752.7
751.9
752.7
752.7
752.2
752.7
752.0
751.9
752.0
751.8
751.7
751.8
751.7
751.5
751.7
33.40
24.26
33.28
33.40
28.31
33.28
31.00
26.19
29.59
30.63
25.83
27.40
27.84
24.26
26.53
33.37
27.78
33.24
33.37
22.87
33.24
26.79
30.12
22.87
24.61
26.21
28.77
C$0.80 C$0.20 C$0.20 C$0.20 C$0.20
204.5
188.0
30.66
23.84
25.79
787.7
241.9
153.3
751.3
751.0
751.4
27.18
24.68
26.50
25.70
23.37
25.20
US$0.20
83.5
(1) Cenovus Common Shares were issued under the terms of the plan of arrangement with Encana Corporation (“Arrangement”) on November 30, 2009 and began trading on December 3, 2009 (TSX) and
December 9, 2009 (NYSE).
(2) Dividend paid in December 2009 reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flows.
121 · SUppLEMENTAL INFOrMATION (UNAUDITED) · CENOVU S 2010 A NNU AL rEpOr
T
F I n A n C I A L s tAt I s t I C s ( C O n t I n u E D )
Net Capital Investment
(C$ millions)
Capital Investment
Upstream
Foster Creek
Christina Lake
Total
pelican Lake
Other Oil Sands
Conventional
refining and Marketing
Corporate
Capital Investment
Acquisitions
Divestitures
Net Acquisition and Divestiture Activity
2010
2009
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
278
346
624
104
139
523
1,390
656
76
2,122
86
(307)
(221)
110
106
216
37
60
216
529
139
38
706
48
5
53
59
93
152
17
17
136
322
147
11
480
4
(168)
(164)
52
84
136
28
19
68
251
166
26
443
34
(72)
(38)
57
63
120
22
43
103
288
204
1
493
–
(72)
(72)
421
262
224
486
72
71
466
1,095
1,033
34
2,162
148
(367)
76
66
142
13
5
97
257
229
21
507
146
(366)
(219)
(220)
62
53
115
12
5
91
223
291
1
515
1
2
3
59
49
108
16
15
83
222
264
2
488
1
(3)
(2)
65
56
121
31
46
195
393
249
10
652
–
–
–
1,943
287
518
486
652
Net Capital Investment
1,901
759
316
405
O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s
Upstream production Volumes
Crude Oil and Natural Gas Liquids (bbls/d) (1)
Oil Sands – Heavy
Foster Creek
Christina Lake
Total
pelican Lake
Other (including Senlac)
Conventional Liquids
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (2)
2010
2009
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
51,147
7,898
52,183
8,606
50,269
7,838
59,045 60,789
21,738
22,966
–
–
58,107
23,259
–
51,010
7,716
58,726
23,319
–
51,126
7,420
58,546
23,565
–
37,725
6,698
44,423
24,870
3,057
47,017
7,319
40,367
6,305
54,336
23,804
2,221
46,672
25,671
5,080
34,729
6,530
41,259
23,989
2,574
28,554
6,635
35,189
26,029
2,334
82,011
82,527
81,366 82,045
82,111
72,350
80,361
77,423
67,822
63,552
16,659
29,346
1,171
16,553
29,323
1,190
16,921
28,608
1,172
16,205
29,150
1,166
16,962
30,320
1,156
17,888
30,394
1,206
17,127
30,644
1,183
18,073
29,749
1,242
18,074
30,189
1,184
18,290
31,004
1,213
Total Crude Oil and Natural Gas Liquids
129,187
129,593
128,067
128,566
130,549
121,838
129,315
126,487
117,269
114,059
Natural Gas (MMcf/d)
Oil Sands
Conventional
Total Natural Gas production
43
694
737
39
649
688
44
694
738
46
705
751
45
730
775
53
784
837
47
750
797
55
775
830
57
799
856
52
814
866
(1) Certain volumes for prior periods have been reclassified to conform to current liquids classification.
(2) Natural gas liquids include condensate volumes.
CENOVUS 201 0 A NNUA L rEpOr T · S Up pL EM E NTA L I N FOrMATI ON ( UN AUDITED) · 122
O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s ( C O n t I n u E D )
Average royalty rates
(excluding impact of realized financial hedging)
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
2010
2009
Oil sands
Foster Creek
Christina Lake
pelican Lake
Conventional
Weyburn
Other
Natural Gas Liquids
natural Gas
refining
refinery Operations (1)
Crude oil capacity (Mbbls/d)
Crude oil runs (Mbbls/d)
Crude utilization (%)
refined products (Mbbls/d)
(1) represents 100% of the Wood river and Borger refinery operations.
Selected Average Benchmark prices
Crude Oil Prices (US$/bbl)
West Texas Intermediate (“WTI”)
Western Canada Select (“WCS”)
Differential – WTI/WCS
Condensate – (C5 @ Edmonton)
Differential – WTI/Condensate
(premium)/discount
refining margins 3-2-1 Crack spreads (1) (US$/bbl)
Chicago
Midwest Combined (Group 3)
natural Gas Prices
AECO ($/GJ)
NYMEX (US$/MMBtu)
Differential – NYMEX/AECO (US$/MMBtu)
16.2%
3.9%
21.1%
20.4%
3.6%
21.2%
17.9%
3.9%
18.5%
19.0%
4.4%
23.3%
9.7%
4.0%
21.4%
2.7%
2.3%
20.1%
3.9%
3.6%
19.3%
3.0%
2.9%
20.0%
1.5%
1.6%
19.9%
22.2%
8.2%
1.9%
18.8%
7.2%
1.0%
23.2%
7.1%
2.4%
23.3%
9.1%
2.0%
23.3%
9.1%
2.1%
19.7%
7.2%
1.6%
27.8%
8.4%
1.6%
19.9%
9.1%
2.1%
17.2%
6.6%
1.9%
1.4%
1.0%
21.7%
10.3%
2.4%
1.0%
1.6%
1.7%
2.4%
1.7%
2.8%
1.5%
3.9%
0.5% –0.9%
2.8%
2010
2009
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
452
386
86%
405
452
410
91%
434
452
401
89%
409
452
379
84%
398
452
355
79%
377
452
394
87%
417
452
348
77%
370
452
425
94%
451
452
404
89%
428
452
398
88%
421
2010
2009
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
79.61
65.38
14.23
81.91
85.24
67.12
18.12
85.24
76.21
60.56
15.65
74.53
78.05
63.96
14.09
82.87
78.88
69.84
9.04
84.98
62.09
52.43
9.66
61.35
76.13
64.01
12.12
74.42
68.24
58.06
10.18
65.76
59.79
52.37
7.42
58.07
43.31
34.38
8.93
46.26
(2.30)
–
1.68
(4.82)
(6.10)
0.74
1.71
2.48
1.72
(2.95)
9.33
9.48
9.25
9.12
10.34
10.60
11.60
11.38
3.91
4.39
0.40
3.39
3.80
0.28
3.52
4.38
0.78
3.66
4.09
0.32
6.11
6.82
5.08
5.30
0.19
8.54
8.09
5.00
5.52
8.48
8.06
10.95
9.16
3.92
3.99
0.40
4.01
4.17
0.19
2.87
3.39
0.67
3.47
3.50
0.39
9.75
9.62
5.34
4.89
0.35
(1) 3-2-1- Crack Spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of ultra low sulphur diesel.
123 · SUppLEMENTAL INFOrMATION (UNAUDITED) · CENOVU S 2010 A NNU AL rEpOr
T
O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s ( C O n t I n u E D )
per-unit results
(C$, excluding impact of realized financial hedging)
2010
2009
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
Heavy Oil – Foster Creek ($/bbl) (1)
price
royalties
Transportation and blending
Operating
58.76
9.08
2.42
10.44
58.76
11.41
2.54
10.00
58.51
9.56
2.40
10.35
54.75
9.38
2.40
10.36
63.33
5.76
2.33
11.11
55.55
1.42
2.51
11.87
63.60
2.31
1.71
10.43
62.20
1.85
2.50
10.85
54.43
0.66
3.45
11.81
33.44
0.22
2.69
15.91
Netback
36.82
34.81
36.20
32.61
44.13
39.75
49.15
47.00
38.51
14.62
Heavy Oil – Christina Lake ($/bbl) (2)
price
royalties
Transportation and blending
Operating
57.96
2.14
3.54
16.56
58.42
2.05
1.54
17.40
56.45
2.04
3.69
15.94
54.99
2.19
4.52
16.50
62.27
2.28
4.47
16.41
53.45
1.24
3.09
16.31
57.07
2.04
0.96
18.06
64.85
1.72
5.36
15.31
57.32
0.83
2.83
13.69
32.44
0.23
3.38
18.21
Netback
35.72
37.43
34.78
31.78
39.11
32.81
36.01
42.46
39.97
10.62
Heavy Oil – pelican Lake ($/bbl) (3)
price
royalties
Transportation and blending
Operating
62.65
12.96
1.42
12.76
61.38
12.76
1.04
13.37
58.93
10.62
1.77
13.26
62.05
14.06
1.52
13.29
68.04
14.34
1.30
11.23
54.77
10.98
0.30
9.59
62.73
12.08
(0.02)
11.64
61.87
12.27
0.67
7.03
55.39
10.93
0.06
9.74
38.66
8.57
0.45
10.15
Netback
35.51
34.21
33.28
33.18
41.17
33.90
39.03
41.90
34.66
19.49
Heavy Oil – Oil Sands ($/bbl) (1) (2) (3)
price
royalties
production and mineral taxes
Transportation and blending
Operating
59.76
9.53
–
2.25
11.70
59.35
10.79
–
2.08
11.54
58.41
9.30
–
2.35
11.83
56.83
10.03
–
2.35
11.81
64.61
7.94
–
2.23
11.65
55.09
4.98
0.04
1.81
11.49
62.75
5.37
0.02
1.14
11.41
62.23
5.66
0.07
2.15
9.69
55.18
4.86
0.06
2.16
11.53
35.47
3.69
–
1.85
13.89
Netback
36.28
34.94
34.93
32.64
42.79
36.77
44.81
44.66
36.57
16.04
Heavy Oil – Conventional ($/bbl) (4)
price
royalties
production and mineral taxes
Transportation and blending
Operating
Netback
Total Heavy Oil ($/bbl) (5)
price
royalties
production and mineral taxes
Transportation and blending
Operating
Netback
63.18
9.01
0.19
0.56
12.08
60.45
8.01
0.05
0.45
12.47
59.40
7.29
0.17
0.60
11.52
61.35
9.65
0.10
0.60
12.95
71.16
10.99
0.44
0.59
11.45
55.29
5.47
0.14
1.91
9.47
62.09
8.61
0.13
1.59
12.06
64.62
8.39
(0.04)
1.22
9.31
56.00
4.13
0.44
2.75
9.72
37.71
0.61
0.02
2.11
6.91
41.34
39.47
39.82
38.05
47.69
38.30
39.70
45.74
38.96
28.06
60.33
9.44
0.03
1.97
11.77
59.53
10.36
0.01
1.83
11.68
58.59
8.95
0.03
2.04
11.77
57.57
9.97
0.02
2.06
11.99
65.76
8.48
0.08
1.94
11.61
55.14
5.08
0.06
1.83
11.07
62.63
5.95
0.04
1.22
11.52
62.72
6.22
0.04
1.96
9.61
55.36
4.70
0.14
2.28
11.13
35.99
2.98
-
1.91
12.27
37.12
35.65
35.80
33.53
43.65
37.10
43.90
44.89
37.11
18.83
CENOVUS 201 0 A NNUA L rEpOr T · S Up pL EM E NTA L I N FOrMATI ON ( UN AUDITED) · 124
O P E r At I n G s tAt I s t I C s - B E F O r E r OYA L t I E s ( C O n t I n u E D )
Light and Medium Oil ($/bbl)
price
royalties
production and mineral taxes
Transportation and blending
Operating
Netback
Total Crude Oil ($/bbl)
price
royalties
production and mineral taxes
Transportation and blending
Operating
Netback
Natural Gas Liquids ($/bbl)
price
royalties
Netback
Total Liquids ($/bbl)
price
royalties
production and mineral taxes
Transportation and blending
Operating
Netback
Total Natural Gas ($/Mcf)
price
royalties
production and mineral taxes
Transportation and blending
Operating
Netback
Total ($/BOE)
price
royalties
production and mineral taxes
Transportation and blending
Operating (6)
Netback
2010
2009
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
71.63
9.30
2.55
1.66
12.27
45.85
62.98
9.41
0.62
1.90
11.89
39.16
72.98
7.69
2.45
1.89
12.99
47.96
62.75
9.72
0.59
1.84
11.99
38.61
68.37
9.32
2.44
1.81
12.02
66.14
10.17
3.08
1.51
12.84
42.78
38.54
60.86
9.03
0.59
1.99
11.83
59.51
10.01
0.71
1.94
12.19
78.78
10.05
2.25
1.45
11.25
53.78
68.87
8.85
0.59
1.83
11.52
37.42
34.66
46.08
61.00
1.12
63.60
0.75
59.88
62.85
62.96
9.33
0.62
1.88
11.78
62.75
9.63
0.59
1.82
11.84
54.43
1.29
53.14
60.80
8.96
0.59
1.97
11.72
58.71
1.16
57.55
59.50
9.93
0.71
1.94
12.08
67.42
1.39
66.03
68.85
8.78
0.59
1.83
11.42
63.34
7.39
2.40
0.98
9.93
71.82
11.72
1.70
0.70
9.53
68.15
8.09
2.57
0.83
10.00
65.28
6.56
1.98
1.18
9.53
42.64
48.17
46.66
46.03
57.22
5.67
0.65
1.61
10.78
38.51
49.08
0.81
48.27
57.14
5.62
0.65
1.60
10.67
64.85
7.34
0.44
1.10
11.04
44.93
59.06
0.96
58.10
64.79
7.28
0.44
1.09
10.94
64.00
6.66
0.64
1.69
9.70
45.31
57.95
5.18
0.62
2.00
10.72
39.43
49.17
1.00
44.65
0.82
48.17
43.83
63.85
6.60
0.63
1.67
9.61
57.81
5.14
0.61
1.98
10.61
39.35
38.87
37.56
34.84
46.23
38.60
45.04
45.34
39.47
4.09
0.07
0.02
0.17
0.96
2.87
44.01
4.93
0.37
1.45
8.81
28.45
3.55
(0.04)
0.02
0.16
1.02
2.39
42.82
4.90
0.35
1.40
9.08
27.09
3.68
0.08
0.03
0.15
0.94
2.48
41.49
4.73
0.38
1.42
8.70
3.78
0.07
(0.04)
0.15
0.94
2.66
41.46
5.26
0.24
1.43
8.93
5.27
0.14
0.07
0.21
0.94
3.91
50.16
4.81
0.52
1.53
8.53
26.26
25.60
34.77
4.15
0.08
0.05
0.15
0.86
3.01
39.88
2.87
0.46
1.24
7.71
27.60
4.17
0.16
0.03
0.12
0.81
3.05
44.54
4.05
0.30
0.91
7.85
3.14
0.02
0.04
0.16
0.84
2.08
40.43
3.22
0.43
1.29
7.24
3.80
0.01
0.07
0.16
0.83
2.73
38.65
2.35
0.52
1.41
7.52
31.43
28.25
26.85
48.09
3.14
3.37
1.21
10.67
29.70
39.40
3.03
0.95
1.71
11.82
21.89
43.42
0.46
42.96
39.45
3.00
0.94
1.69
11.69
22.13
5.47
0.15
0.05
0.18
0.94
4.15
35.71
1.81
0.58
1.34
8.27
23.71
(1) The Foster Creek 2010 YTD heavy oil price and transportation and blending costs exclude the costs of condensate purchases ($35.43/bbl) which are blended with the heavy oil.
(2) The Christina Lake 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($36.66/bbl) which are blended with the heavy oil.
(3) The pelican Lake 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($14.69/bbl) which are blended with the heavy oil.
(4) The Conventional 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($11.08/bbl) which are blended with the heavy oil.
(5) The total 2010 YTD heavy oil price and transportation and blending costs exclude the cost of condensate purchases ($26.88/bbl) which are blended with the heavy oil.
(6) 2010 YTD operating costs include costs related to long-term incentives of $0.15/BOE (2009 – $0.09/BOE).
Impact of realized Financial Hedging
Liquids ($/bbl)
Natural Gas ($/Mcf)
Total ($/BOE)
(0.36)
1.07
2.99
(1.29)
1.50
3.65
1.01
1.09
3.77
(0.40)
1.22
3.37
(0.78)
0.53
1.20
1.10
3.63
12.16
(0.05)
2.27
6.92
(0.01)
4.41
13.77
1.54
4.33
14.91
3.29
3.43
13.06
125 · SUppLEMENTAL INFOrMATION (UNAUDITED) · CENOVU S 2010 A NNU AL rEpOr
T
R ESE RvES data and O thER Oil and gaS i nFORMatiOn
r E s E rv E s DA tA A n D O t H E r O I L A n D G A s I n F O r m At I O n
For information in relation to the presentation of our reserves data and
other oil and gas information, see the Oil and Gas reserves and resources
section of our MD&A. We hold significant freehold title rights which generate
production for our account from third parties leasing those lands. The Before
royalty volumes presented do not include reserves associated with this
royalty Interest production. The After royalty volumes presented include
our royalty Interest reserves.
For definitions of the terms used in our oil and gas disclosure, please refer to
the Additional Advisory on page 132.
s u m m A rY O F O I L A n D G A s r E s E rv E s A t D E C E m B E r 3 1 , 2 0 1 0
( F O r E C A s t P r I C E s A n D C O s t s )
C O M Pa n y i n t E R E S t B E F O R E R Oya lt i E S ( 1 )
Classifications of reserves as proved or probable are only attempts to define
the degree of certainty associated with the estimates. There are numerous
uncertainties inherent in estimating quantities of bitumen, oil and natural gas
reserves. it should not be assumed that the estimates of future net revenues
presented in the tables below represent the fair market value of the reserves.
There is no assurance that the forecast prices and costs assumptions will be
attained and variances could be material. For additional information on our
pricing assumptions, reserves data and other oil and gas information, readers
should review “reserves Data and Other Oil and Gas Information” and
“risk Factors – Uncertainty of reserves, resources and Future Net revenue
Estimates”, each within our AIF for the year ended December 31, 2010,
available at www.sedar.com and at www.cenovus.com.
Bitumen
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Heavy Oil
(MMbbls)
Natural Gas
& CBM
(Bcf)
126
20
1,008
1,154
523
1,677
111
13
45
169
97
266
79
5
27
111
49
160
1,292
62
36
1,390
410
1,800
Bitumen
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Heavy Oil
(MMbbls)
Natural Gas
& CBM
(Bcf)
96
14
760
870
404
1,274
92
10
36
138
72
210
67
4
21
92
39
131
1,292
61
36
1,389
391
1,780
reserves Category
Proved reserves
Developed producing
Developed Non-producing
Undeveloped
total Proved reserves
Probable reserves
total Proved plus Probable reserves
note:
(1) Does not include royalty Interest reserves associated with royalty Interest production received by Cenovus.
C O M Pa n y i n t E R E S t a F t E R R Oya lt i E S ( 1 )
reserves Category
Proved reserves
Developed producing
Developed Non-producing
Undeveloped
total Proved reserves
Probable reserves
total Proved plus Probable reserves
note:
(1) Includes royalty Interest reserves associated with royalty Interest production received by Cenovus.
CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 126
s u m m A rY O F n E t P r E s E n t vA L u E O F F u t u r E n E t r E v E n u E A t D E C E m B E r 3 1 , 2 0 1 0
( F O r E C A s t P r I C E s A n D C O s t s )
Before Income Taxes
Discounted at %/year ($ millions)
Unit Value
Before
Income Tax
Discounted
at 10% (1)
0%
5%
10%
15%
20%
$/BOE
16,118
1,423
36,936
54,477
21,163
12,796
888
13,789
27,473
12,192
10,619
604
6,302
17,525
6,879
9,102
435
3,300
12,837
4,031
7,986
325
1,872
10,183
2,466
75,640
39,665
24,404
16,868
12,649
22.60
15.53
7.66
13.16
11.84
12.76
After Income Taxes (1)
Discounted at %/year ($ millions)
0%
5%
10%
15%
20%
12,683
1,070
27,637
10,153
666
10,359
8,480
454
4,720
7,308
328
2,442
6,443
245
1,349
41,390
21,178
13,654
10,078
8,037
15,783
9,073
5,076
2,923
1,737
57,173
30,251
18,730
13,001
9,774
reserves Category
Proved reserves
Developed producing
Developed Non-producing
Undeveloped
total Proved reserves
Probable reserves
total Proved plus Probable reserves
note:
(1) Unit values have been calculated using the Company Interest After royalties reserves
reserves Category
Proved reserves
Developed producing
Developed Non-producing
Undeveloped
total Proved reserves
Probable reserves
total Proved plus Probable reserves
note:
(1) After income tax values are calculated by considering the Company’s existing tax pools
the estimates of future net revenue presented do not represent fair market value.
127 · rESEr VES DATA AND OTHEr OIL AND GAS INFOrMATION · CENOVU S 2010 A NNU AL rEpOr T
r E s E rv E s r E C O n C I L I At I O n
The following tables provide a reconciliation of our company interest reserves Before royalties for bitumen, heavy oil, light and medium oil and NGLs, and
natural gas for the year ended December 31, 2010, presented using forecast prices and costs. All reserves are located in Canada.
r E s E rv E s r E C O n C I L I At I O n BY P r I n C I PA L P r O D u C t t Y P E A n D r E s E rv E s C At E G O rY
( F O r E C A s t P r I C E s A n D C O s t s )
C O M Pa n y i n t E R E S t P R Ov E d – B E F O R E R Oya lt i E S
December 31, 2009 (sEC) (1)
Transition to NI 51-101 Standards (2)
December 31, 2009 (nI 51-101)
Extensions and Improved recovery
Discoveries
Technical revisions
Economic Factors
Acquisitions
Dispositions
production (3)
December 31, 2010
C O M Pa n y i n t E R E S t P R O B a B l E – B E F O R E R Oya lt i E S
December 31, 2009 (sEC) (1)
Transition to NI 51-101 Standards (2)
December 31, 2009 (nI 51-101)
Extensions and Improved recovery
Discoveries
Technical revisions
Economic Factors
Acquisitions
Dispositions
production
December 31, 2010
Bitumen
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Heavy Oil
(MMbbls)
Natural Gas
& CBM
(Bcf)
866
–
866
270
–
40
–
–
–
(22)
1,154
165
(1)
164
9
–
15
–
–
(5)
(14)
169
112
(3)
109
11
–
1
–
–
–
(10)
111
1,529
128
1,657
45
–
60
(18)
–
(87)
(267)
1,390
Bitumen
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Heavy Oil
(MMbbls)
Natural Gas
& CBM
(Bcf)
479
–
479
132
–
(88)
–
–
–
–
523
104
(1)
103
5
–
(10)
–
–
(1)
–
97
53
(2)
51
(1)
–
(1)
–
–
–
–
49
436
52
488
12
–
(82)
7
–
(15)
–
410
CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 128
C O M Pa n y i n t E R E S t P R Ov E d P l U S P R O B a B l E – B E F O R E R Oya lt i E S
December 31, 2009 (sEC) (1)
Transition to NI 51-101 Standards (2)
December 31, 2009 (nI 51-101)
Extensions and Improved recovery
Discoveries
Technical revisions
Economic Factors
Acquisitions
Dispositions
production (3)
December 31, 2010
Bitumen
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Heavy Oil
(MMbbls)
Natural Gas
& CBM
(Bcf)
1,345
–
1,345
402
–
(48)
–
–
–
(22)
1,677
269
(2)
267
14
–
5
–
–
(6)
(14)
266
165
(5)
160
10
–
–
–
–
–
(10)
160
1,965
180
2,145
57
–
(22)
(11)
–
(102)
(267)
1,800
notes:
(1) references in the tables to December 31, 2009 (SEC) numbers are to the previously disclosed estimates as of that date prepared by the IQrEs in accordance with U.S. disclosure requirements using constant
prices and costs as prescribed by the SEC.
(2) The change in reserves disclosed in the transition from SEC to NI 51-101 is a result of (i) the forecast prices and costs used under NI 51-101 were higher than the SEC prescribed constant prices and costs,
restoring previously uneconomic gas reserves, and (ii) the removal of royalty Interest reserves from the Before royalties reserves totals.
(3) production used for the reserves reconciliation differs from reported production. Company Interest Before royalties production for reserves includes Cenovus’s share of gas volumes provided to Cenovus’s
share of the FCCL partnership for steam generation, but does not include royalty interest production, as prescribed by NI 51-101.
E C O n O M i C C O n t i n g E n t a n d P R O S P E C t i v E R E S O U R C E S
Company Interest Before r oyalties, Billions of barrels, Bitumen
Economic Contingent resources (3)
Low Estimate
Best Estimate
High Estimate
Prospective resources (4)
Low Estimate
Best Estimate
High Estimate
December 31,
2010 (1)
December 31,
2009 (2)
4.4
6.1
8.0
7.3
12.3
21.7
3.9
5.4
7.3
7.8
12.6
21.4
notes:
(1) refers to estimates prepared by McDaniel using the same forecast prices and costs as used in the 2010 reserves estimates, McDaniel January 1, 2011 forecast prices and costs.
(2) refers to previously disclosed estimates prepared by McDaniel, using 2009 constant prices and costs.
(3) There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
(4) There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective
resources. prospective resources are not screened for economic viability.
129 · rESEr VES DATA AND OTHEr OIL AND GAS INFOrMATION · CENOVU S 2010 A NNU AL rEpOr T
E X P L O r At I O n A n D D E v E L O P m E n t AC t I v I t Y
The following tables summarize our gross participation and net interest in wells drilled for the periods indicated.
E x P lO R at i O n W E l l S d Ri l lE d
2010:
Oil Sands
Conventional
Total Canada
2009:
Oil Sands
Conventional
Total Canada
2008:
Oil Sands
Conventional
Total Canada
d E v E lO P M E n t W E l l S d Ri l lE d
2010:
Oil Sands
Conventional
Total Canada
2009:
Oil Sands
Conventional
Total Canada
2008:
Oil Sands
Conventional
Total Canada
Oil
Gas
Dry &
Abandoned
Total
Working
Interest
royalty
Total
Gross Net
Gross Net
Gross Net
Gross Net
Gross
Gross Net
–
26
26
–
4
4
–
1
1
–
26
26
–
4
4
–
1
1
–
–
–
–
–
–
–
5
5
–
–
–
–
–
–
–
3
3
–
1
1
–
–
–
–
2
2
–
1
1
–
–
–
–
1
1
–
27
27
–
4
4
–
8
8
–
27
27
–
4
4
–
5
5
–
21
21
–
8
8
–
34
34
–
48
48
–
12
12
–
42
42
–
27
27
–
4
4
–
5
5
Oil
Gas
Dry &
Abandoned
Total
Working
Interest
royalty
Total
Gross Net
Gross Net
Gross Net
Gross Net
Gross
Gross Net
82
160
47
154
–
499
–
495
242
201
499
495
50
102
29
101
8
555
8
502
–
–
–
8
2
–
–
–
8
2
82
659
47
649
741
696
66
659
45
605
152
130
563
510
10
10
725
650
41
105
146
21
92
113
13
1,489
13
1,372
1,502
1,385
4
7
11
4
7
11
58
1,601
38
1,471
1,659 1,509
8
204
212
10
261
271
41
503
544
90
863
47
649
953
696
76
920
45
605
996
650
99
2,104
38
1,471
2,203 1,509
In addition to the disclosure above, we drilled stratigraphic test wells during
the year ended December 31, 2010, with Oil Sands having drilled 259 gross wells
(178 net wells) and Conventional having drilled 11 gross wells (9 net wells).
In addition to the disclosure above, we drilled service wells during the year
ended December 31, 2010, with Oil Sands having drilled 68 gross wells (44 net
wells) and Conventional having drilled 30 gross wells (20 net wells).
CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 130
I n t E r E s t I n m A t E r I A L P r O P E r t I E s
The following table summarizes our developed, undeveloped and total landholdings at December 31, 2010.
( t h o u s a n d s o f a c r e s)
Alberta:
Oil Sands
– Crown (3)
Conventional
– Fee (4)
– Crown (3)
– Freehold (5)
Total Alberta
saskatchewan:
Conventional
– Fee (4)
– Crown (3)
– Freehold (5)
Total Saskatchewan
manitoba:
Conventional – Fee (4)
Total Manitoba
total
Developed
Undeveloped (1)
Total (2)
Gross
Net
Gross
Net
Gross
Net
696
1,913
1,571
51
4,231
69
47
13
129
3
3
597
1,913
1,463
42
4,015
69
34
9
112
3
3
1,845
440
372
35
2,692
437
162
28
627
261
261
1,455
440
306
32
2,233
437
141
25
603
261
261
4,363
4,130
3,580
3,097
2,541
2,353
1,943
86
6,923
506
209
41
756
264
264
7,943
2,052
2,353
1,769
74
6,248
506
175
34
715
264
264
7,227
notes:
(1) Undeveloped includes land that has not yet been drilled, as well as land with wells that have never produced hydrocarbons or that do not currently allow for the production of hydrocarbons.
(2) This table excludes approximately 2.4 million gross acres under lease or sublease, reserving to us, royalties or other interests.
(3) Crown/Federal lands are those lands owned by the federal or provincial government or the First Nations, in which we have purchased a working interest lease.
(4) Fee lands are those lands in which we have a fee simple interest in the mineral rights and have either: (i) not leased out all of the mineral zones; or (ii) retained a working interest. The current fee lands
summary now includes all fee titles owned by us, that have one or more zones that remain unleased or available for development.
(5) Freehold lands are those lands owned by individuals (other than a government or Cenovus) in which Cenovus holds a working interest lease.
131 · rESEr VES DATA AND OTHEr OIL AND GAS INFOrMATION · CENOVU S 2010 A NNU AL rEpOr T
A D D I t I O nA L A D v I s O rY
O i l a n d g a S i n F O R M at i O n
F i n d i n g a n d d E v E lO P M E n t C O S t S
Finding and development costs disclosed on pages 25 and 33 of this
Annual report do not include changes in estimated future development
costs and exclude the effects of acquisitions and dispositions. Cenovus
uses finding and development costs without changes in estimated future
development costs as an indicator of relative performance to be consistent
with the methodology accepted within the oil and gas industry. Finding and
development costs excluding the effects of acquisitions and dispositions
and without changes in future development costs is equal to finding and
development capital investment divided by finding and development reserves
additions. Finding and development reserves additions are calculated by
summing revisions, improved recovery, extensions and discoveries.
Finding and development costs for proved reserves, excluding the effects of
acquisitions and dispositions but including the change in estimated future
development costs were $10.55/BOE for the year ended December 31, 2010,
$16.01/BOE for the year ended December 31, 2009 and averaged $16.95/BOE
for the three years ended December 31, 2010. Finding and development costs
for proved plus probable reserves, excluding the effects of acquisitions and
dispositions but including the change in estimated future development
costs were $9.78/BOE for the year ended December 31, 2010, $81.70/BOE
for the year ended December 31, 2009 and averaged $24.43/BOE for the
three years ended December 31, 2010. These finding and development costs
were calculated by dividing the sum of exploration costs, development
costs and changes in future development costs in the particular year by the
reserves additions (the sum of discoveries, extensions and improved recovery
and technical revisions) in that year. The aggregate of the exploration and
development costs incurred in a particular year and the change during that
year in estimated future development costs generally will not reflect total
finding and development costs related to reserves additions for that year.
For additional information about our finding and development costs, capital
investment and reserves additions, please see our February 18, 2011 news
release available at www.sedar.com and www.cenovus.com.
The following definitions are applicable to our oil and gas disclosure in this
Annual report. For definitions related to our contingent and prospective
resources disclosure, see “Oil and Gas Information” in the Advisory section of
our MD&A. For additional definitions that are not included here, please see
“reserves Data and Other Oil and Gas Information” within our AIF for the year
ended December 31, 2010, available at www.sedar.com and at www.cenovus.com.
after Royalties means volumes after deduction of royalties and including any
royalty interests.
Before Royalties means volumes before deduction of royalties and excluding
any royalty interests.
Bitumen initially-in-place
discovered bitumen initially-in-place (56 Bbbls) is the quantity of
bitumen estimated, as at December 31, 2009 by an independent qualified
reserves evaluator, to be contained in known accumulations prior to
production. The recoverable portion of discovered bitumen initially-
in-place includes production, reserves, and contingent resources; the
remainder is categorized as unrecoverable. There is no certainty that it
will be commercially viable to produce any portion of the estimate.
total bitumen initially-in-place (BIIp) (137 Bbbls) is the quantity of bitumen
estimated, as at December 31, 2009 by an independent qualified reserves
evaluator, to exist originally in naturally occurring accumulations. It
includes Discovered BIIp (56 Bbbls) plus Undiscovered BIIp (82 Bbbls)
which includes those estimated quantities, as at December 31, 2009, in
accumulations yet to be discovered. There is no certainty that any portion
of the estimate will be discovered. If discovered, there is no certainty that
it will be commercially viable to produce any portion of the estimate.
Bitumen initially-in-place estimates include unrecoverable volumes and
are not an estimate of the volume of the substances that will ultimately
be recovered. For further information regarding these estimates and all
subcategories thereof, please see our June 16, 2010 news release, available at
www.sedar.com and www.cenovus.com.
Company interest means, in relation to production, reserves, resources and
property, the interest (operating or non-operating) held by Cenovus.
Royalty interest means:
(a) in relation to reserves, those reserves related to our royalty
entitlement on lands to which we hold freehold title which have
been leased to third parties, or reserves related to other royalty
interests, such as overriding royalties to which we are entitled.
(b) in relation to production, the production generated for Cenovus’s
account pursuant to leasing agreements of our freehold title lands,
and other royalty entitlement agreements.
CENOVUS 201 0 A NNUA L rEpOr T · rES Er VES DATA AN D OT HEr O IL AND GAS INFOrMATION · 132
We aRe a canaDian oiL coMP anY aPPLYinG
FResh, PRoGRessive thinKinG:
to safely and responsibly unlock energy resources
the world needs – that’s our promise.
to increase total shareholder return – that’s our goal.
pictured here is Foster Creek, our largest steam-assisted gravity drainage (sagD) project,
situated on the Cold lake air Weapons range in northern alberta.
Corporate Information
e xeCutive oFFiCers
Brian C. Ferguson
president & Chief executive officer
John K. Brannan
executive vice-president &
Chief operating officer
harbir s. Chhina
executive vice-president, oil sands
Kerry D. Dyte
executive vice-president, general
Counsel & Corporate secretary
Judy a. Fairburn
executive vice-president,
environment & strategic planning
sheila M. Mcintosh
executive vice-president,
Communications & stakeholder
relations
ivor M. ruste
executive vice-president &
Chief Financial officer
Donald t. swystun
executive vice-president, refining,
Marketing, transportation &
Development
hayward J. Walls
executive vice-president,
organization & Workplace
Development
BoarD oF DireCtors
Michael a. grandin(1)(4)(8)
Chair, Calgary, alberta
ralph s. Cunningham(1)(3)(4)(6)
houston, texas
patrick D. Daniel(1)(2)(3)(4)
Calgary, alberta
ian W. Delaney(1)(3)(4)(6)
toronto, ontario
Brian C. Ferguson(7)
Calgary, alberta
valerie a. a. nielsen(1)(2)(4)(5)
Calgary, alberta
Charles M. rampacek(4)(5)(6)
Dallas, texas
Colin taylor (2)(3)(4)
toronto, ontario
Wayne g. thomson(1)(4)(5)(6)
Calgary, alberta
(1) Former director of encana.
(2) Member of the audit committee.
(3) Member of the human Resources and
compensation committee.
(4) Member of the nominating and corporate
Governance committee.
(5) Member of the Reserves committee.
(6) Member of the safety, environment and
Responsibility committee.
(7) as an officer and a non-independent
director, Mr. Ferguson is not a member of
any of the committees of our Board.
(8) ex-officio non-voting member of all other
committees of our Board.
Cenovus he aD &
registereD oFFiCe
cenovus energy inc.
421 – 7 avenue s.W.
Po Box 766
calgary, alberta, canada t2P 0M5
Phone: 403-766-2000
www.cenovus.com
Shareholder Information
annual Meeting
shareholders are invited to
attend the annual meeting being
held on Wednesday, april 27, 2011
at 2 p.m. (calgary time) at the
teLus convention centre,
exhibition hall e, 2nd Floor,
north Building, 136 – 8 avenue s.e.,
calgary, alberta.
Please see our management
proxy circular mailed to
shareholders and posted on our
website, www.cenovus.com, for
additional information.
transFer a gents & registrar
in canada, ciBc Mellon trust
company in calgary, Montreal &
toronto. in the united states, BnY
Mellon in Jersey city, new Jersey.
shareholders are encouraged to
contact ciBc Mellon trust company
for information regarding their
security holdings. they can be
reached throughout north america
by phoning 1-866-332-8898 (english &
French) and outside north america
by phone at 1-416-643-5850 or by
facsimile at 1-416-643-5501.
Canadian stock transfer Company
CiBC Mellon trust Company
Po Box 7010
adelaide street Postal station
toronto, ontario, canada M5c 2W9
www.cibcmellon.com
canadian stock transfer company
inc. recently purchased the transfer
agency business from ciBc Mellon.
canadian stock transfer company
inc. is operating the transfer
agency business in the name of
ciBc Mellon trust company for a
transition period.
shareholDer
aCCount Matters
to change your address, transfer
shares, eliminate duplicate mailings,
deposit dividends directly into
accounts at financial institutions
in canada that provide electronic
fund-transfer services, etc.,
please contact ciBc Mellon
trust company.
stoCK e xChanges
common shares (cve) trade on
the toronto stock exchange
(tsX) and the new York stock
exchange (nYse).
annual inForMation ForM /
ForM 40-F
our annual information Form is
filed with the canadian securities
administrators in canada on
seDaR at www.sedar.com and with
the u.s. securities and exchange
commission under the Multi-
Jurisdictional Disclosure system
as Form 40-F on eDGaR at
www.sec.gov.
nyse s tat eMent oF
DiFFerenCes
as a canadian company listed
on the new York stock exchange
(nYse), we are not required to
comply with most of the nYse
corporate governance standards
and instead may comply with
canadian corporate governance
requirements. We are, however,
required to disclose the significant
differences between our corporate
governance practices and those
required to be followed by u.s.
domestic companies under the
nYse corporate governance
standards. except as summarized on
our website, www.cenovus.com, we
are in compliance with the nYse
corporate governance standards in
all significant respects.
investor rel ations
Please visit the Invest In Us
section of www.cenovus.com
for investor information.
investor inquiries should be
directed to:
403-766-7711
investor.relations@cenovus.com
or
susan grey
Director, investor Relations
403-766-4751
susan.grey@cenovus.com
Media inquiries should be
directed to:
403-766-7751
media.relations@cenovus.com
or
rhona DelFrari
Manager, Media Relations
403-766-4740
rhona.delfrari@cenovus.com
133 · c oRPoRate anD sh aRehoLDeR inFoRMat i on · ce n ov us 20 10 a nn u aL RePoR
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20 10 ann ual report
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Brian Ferguson talks about Cenovus, our
operations and how we’re doing things
differently. Want to see the video? Download
a free Qr code reader on your mobile browser.
Front cover: Staff from our Christina Lake site
Cenovus energy inC .
421 – 7 avenue sW
po Box 766
Calgary, alberta, Canada
t2p 0M5
printed in Canada.