Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) delivered strong
operating performance in 2018 while demonstrating financial
resilience in a challenging and volatile Canadian commodity price
environment.
“In the fourth quarter, in some of the most difficult
macro-economic conditions we’ve ever faced and while voluntarily
managing our oil sands production lower, we remained relatively
cash-flow neutral and continued to deleverage our balance sheet. I
believe we are well positioned to make material progress on our
business plan and further deleverage in 2019,” said Alex Pourbaix,
Cenovus President & Chief Executive Officer. “Over the past
year, Cenovus has become a stronger company through our focus on
capital discipline and cost leadership while maintaining safe and
reliable operations.”
Overall, Cenovus’s 2018 upstream financial results were
significantly impacted by widening light-heavy oil price
differentials, which reached historical highs in the fourth
quarter, as well as realized hedging losses of $1.6 billion largely
in the first three quarters of the year. At the same time, the
wider differentials created a feedstock cost advantage for the
company’s jointly owned refineries. Cenovus’s $2.9 billion net loss
from continuing operations last year included three large non-cash
charges: an exploration expense in the Deep Basin segment, a
significant provision for office space that exceeds the company’s
long-term requirements and a loss on the sale of the Pipestone
business.
While managing through the market challenges of the fourth
quarter, Cenovus continued to progress its deleveraging plans. The
company reduced gross debt by 16% or US$1.2 billion during the
fourth quarter of 2018 and January of this year.
Key 2018 developments
- Achieved record low per-barrel oil sands sustaining capital and
operating costs
- Repaid US$876 million of unsecured notes, reducing year-end net
debt to about C$8.4 billion. Repurchased another US$324 million in
January 2019 at a discount
- Generated refining and marketing operating margin of $996
million
- Reduced capital spending by 18% compared with 2017, with
decreased spending on continuing operations largely the result of
lower oil sands sustaining capital costs
- Sold the Suffield and Pipestone businesses in Alberta for total
cash proceeds of just over $1 billion, before closing
adjustments
- Increased committed capacity on the Keystone XL Pipeline
project to 150,000 barrels per day (bbls/d)
- Signed three-year rail agreements to strengthen market
access
- Generated over $2.1 billion in cash from operating activities,
and free funds flow of $311 million
- Achieved upstream production from continuing operations
of 483,000 barrels of oil equivalent per day (BOE/d) while
managing volumes in response to wide differentials
- Progressed Christina Lake phase G, which is under budget and
ahead of schedule
Overview |
|
2018 production & financial summary |
(for the period ended December 31) |
2018Q4 |
2017Q4 |
% change |
2018Full year |
2017Full year |
% change |
Financial($ millions, except per share amounts) |
|
|
|
|
|
|
Cash from operating activities |
485 |
900 |
-46 |
2,154 |
3,059 |
-30 |
Adjusted funds flow1 |
-36 |
866 |
|
1,674 |
2,914 |
-43 |
Per share diluted |
-0.03 |
0.70 |
|
1.36 |
2.64 |
|
Free funds flow1 |
-312 |
283 |
|
311 |
1,253 |
-75 |
Operating earnings (loss) from continuing
operations1 |
-1,670 |
-533 |
|
-2,755 |
-34 |
|
Per share diluted |
-1.36 |
-0.43 |
|
-2.24 |
-0.03 |
|
Net
earnings (loss) from continuing operations |
-1,350 |
-776 |
|
-2,916 |
2,268 |
|
Per share diluted |
-1.10 |
-0.63 |
|
-2.37 |
2.06 |
|
Capital investment |
276 |
583 |
-53 |
1,363 |
1,661 |
-18 |
Production (from continuing operations) (before
royalties) |
|
|
|
|
|
|
Oil sands (bbls/d) |
326,481 |
361,363 |
-10 |
362,996 |
292,479 |
24 |
Deep Basin liquids2 (bbls/d) |
28,111 |
33,147 |
-15 |
32,454 |
20,850 |
56 |
Total liquids2 (bbls/d) |
354,592 |
394,510 |
-10 |
395,450 |
313,329 |
26 |
Total natural gas (MMcf/d) |
469 |
516 |
-9 |
528 |
326 |
62 |
Total production from continuing operations
(BOE/d) |
432,713 |
480,497 |
-10 |
483,458 |
367,635 |
32 |
1 Adjusted funds flow, free funds flow and operating
earnings/loss are non-GAAP measures. See Advisory. 2 Includes oil
and natural gas liquids (NGLs).
Deleveraging and capital disciplineCenovus made
meaningful progress in further deleveraging its balance sheet in
2018 and early 2019. In the fourth quarter of 2018 and January of
this year, the company reduced total debt outstanding by US$1.2
billion or 16%. This includes redeeming US$800 million of the
company’s 2019 unsecured notes and repurchasing a further US$400
million of its outstanding debt at a discount for US$369
million.
Deleveraging continues to be a top financial priority for
Cenovus in 2019 after funding its sustaining capital requirements
and maintaining its current dividend level. Once the company
reduces net debt to below $7 billion and is on track to reach $5
billion, Cenovus expects to begin balancing its capital allocation
decisions to include increased shareholder returns and disciplined
investment in growth. At a net debt level of $5 billion, Cenovus
anticipates being in a position to maintain a target ratio of less
than two times net debt to adjusted earnings before interest,
taxes, depreciation and amortization (EBITDA), at low-cycle
commodity prices.
In 2018, Cenovus reduced total capital expenditures by 18%
compared with the previous year. Spending on continuing operations
decreased largely as a result of the company’s success in further
reducing its oil sands sustaining capital costs. Cenovus remains
focused on cost leadership and capital discipline and is targeting
capital spending in 2019 of between $1.2 billion and $1.4 billion,
the majority of which will go toward sustaining base oil sands
production.
Commodity price impactIn the fourth quarter of
2018, the average price differential between West Texas
Intermediate (WTI) and Western Canadian Select (WCS) more than
tripled, compared with the same period a year earlier, reaching a
record of about US$52/bbl. For the full year, the WTI-WCS
differential averaged US$26.31/bbl, compared with US$11.98/bbl in
2017. The wider average differential and higher condensate costs
consistent with stronger WTI prices negatively impacted upstream
operating margin. However, the wider WTI-WCS differential created a
feedstock cost advantage for Cenovus’s jointly owned U.S.
refineries, as did the wider average price differential between WTI
and West Texas Sour (WTS).
Cenovus’s fourth quarter 2018 results were also negatively
impacted by the timing of condensate and refinery inventory
drawdowns in a falling commodity price environment. Both condensate
blended to produce heavy oil and refinery feedstock used in the
fourth quarter were purchased several months earlier when prices
were higher, resulting in lower earnings in the fourth quarter.
Cenovus expects that in a rising price environment, the lower cost
condensate and refinery feedstock purchased in the latter part of
the fourth quarter will benefit its first-quarter 2019 results.
After reaching a record high in the fourth quarter, the WTI-WCS
price differential narrowed substantially following the Government
of Alberta’s December 2, 2018 announcement of temporary crude oil
and bitumen production curtailments for producers, effective
January 1. In January 2019, differentials remained narrow, and
Cenovus anticipates they will normalize through the year, settling
somewhere around rail transportation economics in the mid-to-high
teens.
Taking into account the government-mandated production
curtailments, Cenovus expects its first-quarter 2019 bitumen and
crude oil production will be a maximum of 348,000 bbls/d. Overall,
the company anticipates that the financial impact of its curtailed
volumes will be more than offset by an expected improvement in WCS
prices, resulting in a positive impact on its cash flow for
2019.
Financial performance In the second and third
quarters of 2018, when Canadian crude oil prices remained somewhat
normalized, Cenovus had combined free funds flow of almost $1.2
billion, reflecting the company’s strong future cash generating
potential. Cenovus had negative free funds flow in the first and
fourth quarters, largely due to wider average oil price
differentials, as well as refinery maintenance, declining WTI
prices and realized hedging losses in the first quarter. Realized
hedging losses for the full year were approximately $1.6 billion
and were primarily related to risk management contracts put in
place in 2017 that have since expired.
Cenovus’s cash from operating activities and adjusted funds flow
declined 30% and 43% respectively in 2018 compared with 2017. The
company had a net loss from continuing operations of approximately
$2.9 billion compared with net earnings from continuing operations
of nearly $2.3 billion a year earlier, when Cenovus recorded a
significant after-tax revaluation gain of $1.9 billion. The 2018
net loss included a $2.1 billion non-cash exploration expense in
the Deep Basin segment, a non-cash provision of nearly $630 million
for office space that exceeds Cenovus’s requirements, severance
costs of $60 million and a before-tax loss of $797 million on the
sale of the Pipestone business.
“While our operational performance in 2018 was excellent, our
overall financial results were impacted by the challenging Canadian
commodity price environment, particularly in the fourth quarter, as
well as our realized hedging losses for the year,” said Pourbaix.
“That said, I remain optimistic about our prospects for 2019. With
the ramp-up of additional rail transport capacity this year and the
anticipated start-up of Enbridge’s Line 3 Replacement Project, we
expect the overall pricing environment to be better than in
2018.”
Market accessCenovus made significant progress
last year in strengthening its long-term market access position
through its previously announced three-year strategic agreements
with major rail companies to transport approximately 100,000 bbls/d
of heavy crude oil from northern Alberta to various destinations on
the U.S. Gulf Coast. Cenovus expects to ramp up its rail capacity
towards 100,000 bbls/d through the remainder of 2019.
The company also recently increased its committed capacity on
the proposed Keystone XL Pipeline from 50,000 bbls/d to 150,000
bbls/d. A portion of this increased capacity was assumed from the
Government of Alberta. With its positions on Keystone XL and the
Trans Mountain Expansion Project, Cenovus now has 275,000 bbls/d of
potential future pipeline capacity to the West Coast and U.S. Gulf
Coast. The company has current firm capacity to the West Coast,
U.S. Gulf Coast and PADD II of 118,000 bbls/d combined.
Operating highlights
Oil sandsCombined production at the Christina
Lake and Foster Creek oil sands operations was nearly 363,000
barrels per day (bbls/d) in 2018, 24% higher than the previous
year, mainly due to Cenovus’s May 17, 2017 asset acquisition, which
included the remaining 50% of Foster Creek and Christina Lake.
Prior to the implementation of government-mandated production
curtailments on January 1, 2019, Cenovus was already proactively
managing oil sands volumes at Foster Creek and Christina Lake in
the first and fourth quarters of 2018 in response to market access
constraints and discounted Canadian heavy oil pricing. As part of
this process, Cenovus demonstrated its ability to reduce production
while maintaining steam injection, allowing the company to safely
and effectively store mobilized barrels in its reservoirs for sale
later when prices improve. Fourth quarter oil sands production was
about 326,000 bbls/d, a 10% decrease from the same period in 2017,
primarily due to the company’s voluntary curtailment of
approximately 51,000 bbls/d in the quarter.
Cenovus had 2018 oil sands sustaining capital costs of
$4.40/bbl, down 31% from $6.34/bbl the previous year. In 2019, the
company expects to reduce its sustaining capital costs to between
$3.50/bbl and $4.00/bbl. Oil sands operating costs were $7.65/bbl
in 2018, 9% lower than the previous year, mainly due to lower
natural gas prices, higher sales volumes, a reduction in workforce
costs, fewer workovers and lower repairs and maintenance costs.
Fourth quarter oil sands operating costs were $8.03/bbl, 4%
lower than in the same period in 2017. Cenovus anticipates
maintaining per-barrel oil sands operating costs in 2019 at about
2018 levels.
At Christina Lake, the steam to oil ratio (SOR) was 1.9 in 2018,
compared with 1.8 in 2017. At Foster Creek, the SOR was 2.8 in 2018
compared with 2.5 a year earlier. SORs increased in 2018 mainly as
a result of Cenovus maintaining steam injection into its reservoirs
while proactively reducing oil production in the first and fourth
quarters.
The Christina Lake phase G expansion, which has approved
capacity of 50,000 bbls/d, is five months ahead of schedule and 25%
below budget, largely due to advances in well pad design, longer
well lengths and increased efficiencies in facility construction.
Cenovus expects phase G to be completed with industry leading
full-cycle capital efficiencies of between $15,000 and $16,000 per
barrel of capacity. First steam was achieved at the end of last
month, and the project is expected to be complete and ready for
production in the second quarter of this year. Cenovus has
flexibility on start-up and will take into consideration whether
mandated production curtailments have been lifted, if crude-by-rail
takeaway capacity in Alberta ramps up as expected, and the
in-service date of Enbridge’s Line 3 Replacement Project.
Deep Basin Production from the Deep Basin
assets, which Cenovus acquired on May 17, 2017, averaged more than
120,000 BOE/d in 2018, 3% higher than during the company’s 229-day
period of ownership in 2017. The increase was primarily due to
strong initial well results following a moderate drilling program
in the first quarter of 2018. This was partially offset by the sale
of the Pipestone business in September 2018. Production from
Pipestone was approximately 8,800 BOE/d prior to the divestiture.
Fourth quarter 2018 production in the Deep Basin was more than
106,000 BOE/d, 10% lower than in the same period a year earlier,
primarily due to the divestiture.
Following the sale of its Pipestone business, Cenovus decided to
scale back plans for additional Deep Basin asset sales in the East
Clearwater area and a portion of the West Clearwater area. As a
result, as at December 31, 2018, these assets are no longer
classified as held for sale for accounting purposes. Cenovus will
only consider pursuing additional transactions in the Deep Basin in
2019 if the company is able to generate strong value for the assets
involved.
Average operating costs in the Deep Basin were $8.58/BOE in
2018, little changed from 2017, while fourth quarter operating
costs were $9.53/BOE, 19% higher than in the same period a year
earlier, largely due to lower production in the quarter. Cenovus
expects to hold per-barrel operating costs essentially flat in 2019
compared with full-year 2018 levels, as production declines.
In 2018, Cenovus conducted a review of its long-term development
plans for the Deep Basin assets. As a result, in the fourth quarter
of 2018, the company wrote off previously capitalized exploration
and evaluation costs as a one-time non-cash exploration expense.
Cenovus’s views on the quality of the Deep Basin assets and their
long-term development potential remain unchanged; however, the
company has decided to slow the pace of development due to the
current outlook for commodity prices and the company’s continued
focus on deleveraging.
As previously announced, Cenovus has limited its investment and
drilling plans for the Deep Basin in 2019. Over the course of the
year, the company will be working to optimize its Deep Basin
operating model with a view to reducing costs, improving efficiency
and maximizing value.
DownstreamCenovus’s Wood River, Illinois and
Borger, Texas refineries, which are co-owned with the operator,
Phillips 66, had strong operational performance in 2018. Refining
and marketing operating margin for 2018 was $996 million compared
with $598 million a year earlier. The year-over-year increase was
largely the result of improved refined product prices and a
feedstock cost advantage driven by wider differentials between WTI
and WCS as well as between WTI and WTS in 2018 compared with 2017.
Fourth quarter 2018 refining and marketing operating margin was
$251 million, compared with $314 million in the same period in
2017. Cenovus’s refining operating margin is calculated on a
first-in, first-out (FIFO) inventory accounting basis. Using
the last-in, first-out (LIFO) accounting method employed by
most U.S. refiners, operating margin from refining and marketing
would have been $118 million higher in 2018, compared with $93
million lower in 2017. In the fourth quarter of 2018, operating
margin from refining and marketing would have been $198 million
higher on a LIFO reporting basis, compared with $83 million lower
in the same quarter of 2017.
Following the completion of major planned turnarounds in early
2018, crude utilization rates at both refineries averaged at or
above nameplate capacity in the second half of the year. As a
result of consistently strong operating performance, high
utilization rates and successful optimization projects, both
refineries have been rerated to reflect higher processing capacity.
Crude capacity at Wood River was rerated to 333,000 bbls/d from
314,000 bbls/d, while capacity at Borger was rerated to 149,000
bbls/d from 146,000 bbls/d, both effective January 1, 2019.
Reserves Cenovus’s proved and probable reserves
are evaluated each year by independent qualified reserves
evaluators (IQREs).
At the end of 2018, Cenovus had total proved reserves of
approximately 5.2 billion BOE, in line with 2017, while total
proved plus probable reserves decreased 2% to approximately 7
billion BOE. Proved bitumen reserves were approximately 4.8 billion
barrels, while proved plus probable bitumen reserves were 6.4
billion barrels, both relatively unchanged from 2017.
Cenovus’s 2018 proved reserves finding and development (F&D)
costs were $4.34/BOE, excluding changes in future development
costs, down 40% from 2017, due to reduced capital spending and
higher proved reserves additions in 2018. Three-year average
F&D costs were $4.91/BOE, excluding changes in future
development costs.
More details about Cenovus’s reserves are available under
Financial Information in the Advisory, the company’s Annual
Information Form (AIF) and Annual Report on Form 40-F for the year
ended December 31, 2018, which are available on SEDAR at sedar.com,
EDGAR at sec.gov and Cenovus’s website at cenovus.com.
Management update
Keith Chiasson, who joined the Cenovus Leadership Team in
December 2017 as Senior Vice-President, Downstream has been
promoted to Executive Vice-President, Downstream, effective
immediately.
“Keith has made numerous contributions to Cenovus, including
leading our successful efforts last fall to sign three-year rail
agreements to transport our oil to the U.S. Gulf Coast,” said
Pourbaix. “Given the importance of the downstream portfolio in our
five-year business plan and the critical role market access will
continue to play in Cenovus’s long-term success, I felt it was
important to recognize Keith for his accomplishments so far and for
the high expectations for his role going forward.”
Dividend
For the first quarter of 2019, the Board of Directors declared a
dividend of $0.05 per share, payable on March 29, 2019 to common
shareholders of record as of March 15, 2019. Based on the February
12, 2019 closing share price on the Toronto Stock Exchange of
$10.43, this represents an annualized yield of approximately 1.9%.
Declaration of dividends is at the sole discretion of the Board and
will continue to be evaluated on a quarterly basis.
Year-end disclosure documents Today, Cenovus is
filing its audited Consolidated Financial Statements, Management’s
Discussion and Analysis (MD&A), and AIF, which includes
disclosure relating to reserves data and other oil and gas
information, with Canadian securities regulatory authorities. The
company is also filing its Annual Report on Form 40-F for the year
ended December 31, 2018 with the U.S. Securities and Exchange
Commission. Copies of these documents will be available today on
SEDAR at sedar.com, EDGAR at sec.gov (for the Form 40-F), and the
company's website at cenovus.com under Investors. They can also be
requested free of charge by email at
investor.relations@cenovus.com.
Conference Call Today |
9 a.m. Mountain Time (11 a.m. Eastern Time) |
Cenovus will host a conference call today, February 13, 2019,
starting at 9 a.m. MT (11 a.m. ET). To participate, please dial
888-231-8191 (toll-free in North America) or 647-427-7450
approximately 10 minutes prior to the conference call. A live audio
webcast of the conference call will also be available via
cenovus.com. The webcast will be archived for approximately 90
days. |
ADVISORY
Basis of Presentation – Cenovus reports
financial results in Canadian dollars and presents production
volumes on a net to Cenovus before royalties basis, unless
otherwise stated. Cenovus prepares its financial statements in
accordance with International Financial Reporting Standards
(IFRS).
Barrels of Oil Equivalent – Natural gas volumes
have been converted to barrels of oil equivalent (BOE) on the basis
of six thousand cubic feet (Mcf) to one barrel (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. Given that the value
ratio based on the current price of crude oil compared with natural
gas is significantly different from the energy equivalency
conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is
not an accurate reflection of value.
Finding and Development Costs – Finding and
Development (F&D) costs are calculated by dividing the sum of
total exploration and development costs incurred in 2018 by the sum
of total additions and revisions for proved reserves in the same
period. Proved reserves additions and revisions for the period are
determined by Cenovus's independent qualified reserves evaluators,
effective December 31, 2018, and for purposes of determining
F&D costs, exclude changes resulting from acquisitions,
dispositions and production. F&D costs provide an indication of
the unit cost of finding and developing new reserves. F&D
costs do not have a standardized meaning and are defined
differently by different companies and as such are not comparable
to similar measures presented by other issuers.
Reserves Estimates – Estimates of reserves
referenced in this release were prepared effective December 31,
2018 by independent qualified reserves evaluators, based on the
Canadian Oil and Gas Evaluation Handbook and in compliance with the
requirements of National Instrument 51-101 Standards of Disclosure
for Oil and Gas Activities. Estimates are presented using an
average of the January 1, 2019 price forecasts from three IQREs.
For additional information about our reserves and other oil and gas
information, see “Reserves Data and Other Oil and Gas Information”
in Cenovus's AIF and Annual Report on Form 40-F for the year ended
December 31, 2018 (available on SEDAR at sedar.com, on EDGAR at
sec.gov and Cenovus's website at cenovus.com).
Non-GAAP Measures and Additional Subtotal This
news release contains references to adjusted funds flow, free funds
flow, operating earnings (loss), net debt, and net debt to adjusted
EBITDA, which are non-GAAP measures, and operating margin, which is
an additional subtotal found in Note 1 of Cenovus's Interim
Consolidated Financial Statements (unaudited) for the period ended
December 31, 2018 (available on SEDAR at sedar.com, on EDGAR at
sec.gov and Cenovus's website at cenovus.com). These measures do
not have a standardized meaning as prescribed by IFRS. Readers
should not consider these measures in isolation or as a substitute
for analysis of the company's results as reported under IFRS. These
measures are defined differently by different companies and
therefore are not comparable to similar measures presented by other
issuers. For definitions, as well as reconciliations to GAAP
measures, and more information on these and other non-GAAP measures
and additional subtotals, refer to “Non-GAAP Measures and
Additional Subtotals” in the Advisory section of Cenovus's
Management's Discussion & Analysis (MD&A) for the period
ended December 31, 2018 (available on SEDAR at sedar.com, on EDGAR
at sec.gov and Cenovus's website at cenovus.com).
The following is a reconciliation of adjusted funds flow and
free funds flow to the nearest GAAP measure for the second and
third quarters of 2018:
($ millions) |
Q3 2018 |
Q2 2018 |
Total |
Cash from Operating
Activities |
1,259 |
533 |
1,792 |
Deduct (Add Back) |
|
|
|
Net Change in Other Assets and
Liabilities |
(15) |
(17) |
(32) |
Net Change in Non-Cash Working Capital |
297 |
(224) |
73 |
Adjusted Funds Flow |
977 |
774 |
1,751 |
Capital Investment |
271 |
292 |
563 |
Free Funds Flow |
706 |
482 |
1,188 |
Forward-looking InformationThis news release
contains certain forward-looking statements and forward-looking
information (collectively referred to as “forward-looking
information”) within the meaning of applicable securities
legislation, including the United States Private Securities
Litigation Reform Act of 1995, about our current expectations,
estimates and projections about the future, based on certain
assumptions made by us in light of our experience and perception of
historical trends. Although Cenovus believes that the expectations
represented by such forward-looking information are reasonable,
there can be no assurance that such expectations will prove to be
correct. Readers are cautioned not to place undue reliance on
forward-looking information as actual results may differ materially
from those expressed or implied.
Forward-looking information in this document is identified by
words such as “anticipate”, “believe”, “capacity”, “estimate”,
“expect”, “focus”, “guidance”, “plan”, “position”, “priority”,
“schedule”, “target”, “will”, or similar expressions and includes
suggestions of future outcomes, including statements about: the
strategy and related milestones and schedules; projections for 2019
and future years and our plans and strategies to realize such
projections; priorities and other statements relating to forecast
capital spending, production guidance, debt reduction, including
through free funds flow and asset sales; ability to generate
substantial cash flow and free funds flow in a rising commodity
price environment; targeted net debt and net debt to adjusted
EBITDA ratio and the associated plans if targets are met; expected
impacts of rail commitments; the impact of the Alberta government
mandated production curtailment; the planned timeline for ramping
up oil-by-rail movement; pipeline capacity commitments; long-term
market access position; expected impacts of the actions to mitigate
the impact of wider differentials; the percentage of Cenovus’s
blended heavy oil volumes that can be partially mitigated against
wider differentials; expected outcomes of the company's hedge
positions; the ability to respond to widening differentials by
strategically slowing production; expected impacts of the company's
capacity for storage in its oil sands reservoirs; full-year
production volume and steam to oil ratio forecasts; Christina Lake
phase G expansion progress, including relative to budget and
schedule, expected production capacity and expected capital costs,
including relative to previous estimates; estimates of finding and
development costs; and all statements related to the company’s
updated 2018 guidance.
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 our forward-looking information is based include: Brent price
of US$66.50/bbl, WTI price of US$57.00/bbl; WCS price of
US$30.00/bbl; AECO natural gas price of $1.75/Mcf; Chicago 3-2-1
crack spread of US$16.50/bbl; exchange rate of $0.76 US$/C$ and
other assumptions identified in Cenovus’s updated 2019 Guidance
(dated December 10, 2018) (available at cenovus.com); projected
capital investment levels, the flexibility of capital spending
plans and associated sources of funding; achievement of further
operating efficiencies, cost reductions and sustainability thereof;
lower production as a result of the government-mandated production
curtailment contributing to improvement in WCS prices, and thereby
positive cash flows for 2019; future improvements in availability
of product transportation capacity, including Canadian oil-by-rail
activity ramping up as planned and Enbridge’s Line 3 Replacement
project remaining on track; future narrowing of crude oil
differentials; realization of expected impacts of the company's
storage capacity within its oil sands reservoirs; the ability of
our refining capacity, existing pipeline commitments and plans to
ramp up crude-by-rail loading capacity to mitigate a portion of
heavy oil volumes against wider differentials; low-cycle commodity
prices of US$45/bbl WTI and C$43/bbl WCS; estimates of quantities
of oil, bitumen, natural gas and liquids from properties and other
sources not currently classified as proved; accounting estimates
and judgments; future use and development of technology and
associated expected future results; ability to obtain necessary
regulatory and partner approvals; the successful and timely
implementation of capital projects or stages thereof; ability to
complete asset sales, including with desired transaction metrics
and expected timelines; and ability to access and implement all
technology necessary to achieve expected future results.
Additional information about risks, assumptions, uncertainties
and other factors that could influence Cenovus’s actual results is
provided in Cenovus’s MD&A for the period ended December 31,
2018 as well as its AIF and Form 40-F for the year ended December
31, 2018 (all available on SEDAR at sedar.com, on EDGAR at sec.gov
and Cenovus's website at cenovus.com).
Readers are cautioned that the foregoing lists are not
exhaustive and are made as at the date hereof. Events or
circumstances could cause Cenovus's actual results to differ
materially from those estimated, projected, expressed, or implied
by the forward-looking information. Cenovus undertakes no
obligation to update or revise any forward-looking information
except as required by law.
Cenovus Energy Inc.Cenovus Energy Inc. is a
Canadian integrated oil and natural gas company. It is committed to
maximizing value by responsibly developing its assets in a safe,
innovative and efficient way. Operations include oil sands projects
in northern Alberta, which use specialized methods to drill and
pump the oil to the surface, and established natural gas and oil
production in Alberta and British Columbia. The company also has
50% ownership in two U.S. refineries. Cenovus shares trade under
the symbol CVE, and are listed on the Toronto and New York stock
exchanges. For more information, visit cenovus.com.
Find Cenovus on Facebook, Twitter, LinkedIn, YouTube and
Instagram.
CENOVUS CONTACTS:
Investor
RelationsSherry Wendt Director, Investor
Relations403-766-5489 Mark AustinSenior
Advisor, Investor
Relations403-766-3926
Investor Relations general line403-766-7711 |
Media
Sonja Franklin Senior Media Advisor 403-766-7264
Media Relations general line403-766-7751 |
Photos accompanying this announcement are available at
http://www.globenewswire.com/NewsRoom/AttachmentNg/beca83e2-dcc0-4fd4-938c-b78b5e7f1273
http://www.globenewswire.com/NewsRoom/AttachmentNg/70720fb1-40de-4482-86cd-7c2f26c069ed
http://www.globenewswire.com/NewsRoom/AttachmentNg/f5892585-eda5-48df-ab14-7b346c0ceeb2
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