This news release contains references to the non-GAAP financial
measures “funds from operations”, “free cash flow”, “net debt”,
“net debt to trailing funds from operations”, “EBITDA”, “operating
netback” and “sustaining capital”. Please refer to “Non-GAAP
Measures” at the end of this news release.
Husky Energy (TSX:HSE) generated funds from
operations of $4 billion in 2018, an increase of 21 percent from
2017. Annual net earnings rose 85 percent to $1.5 billion, and free
cash flow was $426 million.
Cash flow provided by operating activities,
which includes changes in non-cash working capital, was $4.1
billion in 2018 compared to $3.7 billion in 2017.
The proved reserves life index was 13.5 years,
an increase from 11 years in 2017.
The 2018 proved reserves replacement ratio was
260 percent, excluding economic factors (255 percent including
economic factors). Total proved reserves before royalties at the
end of 2018 were 1.5 billion barrels of oil equivalent (boe).
Probable reserves were 1.1 billion boe.
Fourth quarter funds from operations was $583
million, compared to $1.3 billion in the previous quarter.
The fourth quarter reduction reflects several
factors:
- Integration benefits were impacted by lower synthetic crude oil
prices due to Canadian pipeline constraints and associated
reductions in margin capture at the Lloydminster Upgrader
- U.S. Downstream results were weakened by narrower crack
spreads, a planned turnaround at the Lima Refinery, and an
unfavourable first-in, first-out (FIFO) pre-tax impact of $181
million ($136 million US)
- Atlantic production volumes were impacted by approximately
10,000 barrels per day (bbls/day) over the quarter due to the
suspension of operations at the SeaRose floating production,
storage and offloading (FPSO) vessel in mid-November
Cash flow provided by operating activities,
which includes changes in non-cash working capital, was $1.3
billion in the fourth quarter compared to $1.4 billion in Q4
2017.
Fourth quarter net earnings were $216 million,
compared to $672 million in Q4 2017.
“It was a challenging quarter,” said CEO Rob
Peabody. “The oil spill on the East Coast was particularly
disappointing, and we are continuing to work closely with the
regulator to determine the root cause and apply learnings.
“We also saw a significant decline in Brent and
WTI oil prices and extreme volatility in the WTI-WCS spread.
Husky’s fourth quarter earnings, adjusted for FIFO impacts,
continues to show the value of the Integrated Corridor business and
the strong contribution of our Asia Pacific business.”
Fourth quarter operational milestones included
record production at the Liwan Gas Project, the Sunrise Energy
Project, the Tucker Thermal Project, and the Rush Lake 2 thermal
bitumen project at Lloydminster.
Husky expects to continue to optimize its
portfolio in 2019 with the strategic review and potential sale of
non-core Downstream assets, along with other actions and
investments aimed at further reducing the Company’s break-even oil
price.
|
Three Months Ended |
|
Twelve Months Ended |
|
Dec. 312018 |
Sept. 302018 |
Dec. 312017 |
|
Dec. 312018 |
Dec. 312017 |
Daily
production, before royalties |
|
|
|
|
|
|
Total equivalent production (mboe/day) |
304 |
297 |
320 |
|
299 |
323 |
Crude oil and natural gas liquids (mbbls/day) |
215 |
210 |
231 |
|
215 |
233 |
Natural gas (mmcf/day) |
538 |
520 |
535 |
|
507 |
539 |
Upstream operating netback1,2
($/boe) |
9.42 |
31.30 |
30.00 |
|
23.98 |
25.25 |
Refinery and Upgrader
throughput (mbbls/day) |
287 |
351 |
387 |
|
347 |
361 |
Cash
flow – operating activities ($mm) |
1,313 |
1,283 |
1,351 |
|
4,134 |
3,704 |
Funds
from operations1 ($mm) Per common share – Basic
($/share) |
5830.58 |
1,3181.31 |
1,0141.01 |
|
4,0043.98 |
3,3063.29 |
Free
cash flow1 ($mm) |
(682) |
350 |
269 |
|
426 |
1,086 |
Net
earnings ($mm) Per common share – Basic ($/share) |
2160.21 |
5450.53 |
6720.66 |
|
1,4571.41 |
7860.75 |
Net
debt3 ($ billions) |
2.9 |
2.6 |
2.9 |
|
2.9 |
2.9 |
Dividend
per common share ($/share) |
0.125 |
0.125 |
0.075 |
|
0.45 |
0.075 |
1Non-GAAP
measure; refer to advisory.2Operating netback includes results from
Upstream Exploration and Production and excludes Upstream
Infrastructure and Marketing.3Net debt is a non-GAAP measure that
equals the sum of long-term debt, long-term debt due within one
year and short-term debt, less cash and cash equivalents.
Refer to advisory. |
FOURTH QUARTER HIGHLIGHTS
- Cash flow from operating activities of $1.3 billion
- Funds from operations of $583 million included an unfavourable
first-in, first-out (FIFO) pre-tax impact of $181 million ($136
million US)
- Capital spending of $1.3 billion reflected higher than
anticipated spending at the West White Rose Project and for U.S.
Downstream maintenance
- Net debt of $2.9 billion represented 0.7 times trailing 12
months funds from operations
- Upstream production of 304,300 boe/day
- Overall operating costs of $13.75 per boe; $11.09 per barrel
for thermal bitumen projects
- Record production from several major assets:
- Sunrise surpassed its design capacity of 60,000 bbls/day, with
a record peak daily rate of 62,600 bbls/day (31,300 bbls/day Husky
working interest)
- Tucker surpassed its design capacity of 30,000 bbls/day, with
Q4 production averaging 25,200 bbls/day
- Rush Lake 2 surpassed its design capacity of 10,000
bbls/day
- Liwan achieved a new quarterly production record, averaging 403
million cubic feet per day (mmcf/day) of natural gas, with
associated liquids averaging 19,200 bbls/day (197 mmcf/day and
9,300 bbls/day Husky working interest)
- Lloydminster asphalt refinery margin of $41.50 per barrel,
compared to $15.79 per barrel in Q4 2017
- Downstream throughput of approximately 287,000 bbls/day;
completed major planned turnaround at the Lima Refinery
- The Lima Refinery is now able to process up to 175,000
bbls/day, up from 165,000 bbls/day
- Sanctioned 10,000 bbls/day thermal project at Spruce Lake East;
first oil expected around the end of 2021
FOURTH QUARTER RESULTS
Upstream production averaged 304,300 boe/day,
compared to 320,400 boe/day in the fourth quarter of 2017. This
takes into account the temporary suspension of production at the
SeaRose FPSO, which returned to operations at the end of January
2019 and will continue to ramp up through the second quarter of
2019.
Upstream operating netbacks averaged $9.42 per
boe, compared to $30 per boe in Q4 2017, which reflects lower
realized heavy oil pricing in the quarter. Average realized pricing
for Upstream production was $25.47 per boe, compared to $46.69 per
boe in the year-ago period. Realized pricing for oil and liquids
averaged $18.93 per barrel, and natural gas averaged $6.86 per
thousand cubic feet (mcf).
Upstream operating costs averaged $13.75 per
boe, up from $13.20 per boe in the fourth quarter of 2017 primarily
due to reduced Atlantic production volumes.
Total Downstream throughput was 286,900 bbls/day
compared to 387,100 bbls/day in Q4 of 2017. This reflects impacts
from a major planned turnaround at the Lima Refinery that was
completed in the fourth quarter, and the continued suspension of
operations at the Superior Refinery.
The Chicago 3:2:1 crack spread averaged $13.38
US per barrel compared to $20.28 US per barrel in Q4 2017. The
average realized U.S. refining and marketing margin was $9.12 US
per barrel of crude throughput, which takes into account an
unfavourable first-in, first-out (FIFO) pre-tax inventory valuation
adjustment of $8.51 US per barrel. This compared to $14.89 US per
barrel a year ago, which included a favourable first-in, first-out
(FIFO) pre-tax inventory valuation adjustment of $2.40 US per
barrel.
The Upgrading realized margin was $29.13 per
barrel, compared to $20.65 per barrel in the year-ago period.
In the Infrastructure and Marketing segment,
EBITDA was $172 million compared to a negative EBITDA of $38
million in the fourth quarter of 2017, primarily reflecting the
value captured from the Company’s long-term 75,000 bbls/day
committed export capacity on the Keystone pipeline and 160 mmcf/day
in natural gas pipeline capacity to U.S. markets.
Capital spending of $1.3 billion primarily
reflected investments in Lloyd thermal projects, Western Canada
resource play drilling, the Lima Refinery turnaround, the Lima
crude oil flexibility project, and the West White Rose Project.
Net debt was $2.9 billion, representing 0.7
times trailing 12 months funds from operations.
INTEGRATED CORRIDOR
- Upstream average production of 240,100 boe/day
- Overall upstream operating netback loss of $3.79 per boe driven
by record wide differentials
- Downstream throughput of 286,900 bbls/day
- Downstream upgrading/refining margin of $21.46 per barrel
Thermal
Production
Total thermal bitumen production from Lloyd
thermal projects, Tucker and Sunrise averaged about 133,000
bbls/day (Husky working interest), compared to about 121,000
bbls/day (Husky working interest) in the fourth quarter of 2017.
Overall operating costs at Sunrise, Tucker and 11 producing Lloyd
thermal projects were approximately $11 per barrel.
At Sunrise, average production in the quarter
was 54,400 bbls/day (27,200 bbls/day Husky working interest), with
a record peak daily rate of 62,600 bbls/day. Tucker achieved its
design capacity of 30,000 bbls/day in the fourth quarter.
The Rush Lake 2 Lloyd thermal project began
production in October 2018 and achieved its 10,000 bbls/day design
capacity the following month.
Five additional 10,000 bbls/day Lloyd thermal
projects are being advanced through 2022, with a combined design
capacity of 50,000 bbls/day. These long-life thermal projects are
being phased to optimize capital efficiency and project
execution.
- At Dee Valley, construction is progressing ahead of schedule
and first oil is on track for the fourth quarter of 2019
- At Spruce Lake Central, the central processing facility is
under construction with first production anticipated in 2020
- At Spruce Lake North, site clearing has been completed with
first oil planned around the end of 2020
- A new 10,000 bbls/day thermal project at Spruce Lake East is
set for first production around the end of 2021
- At Edam Central, regulatory approval has been received, with
first production expected in 2022
Resource Plays
In the Ansell and Kakwa areas of the Wilrich
formation, 21 wells were drilled and 25 completed in 2018. In the
oil and liquids-rich Montney formation, seven wells were drilled
and six completed in the Wembley and Karr areas.
Downstream
Canadian refining throughput, including the
Lloydminster Upgrader and asphalt refinery, averaged 107,800
bbls/day. EBITDA was $252 million.
U.S. refining throughput averaged 179,100
bbls/day. The U.S. refining segment realized EBITDA of $379
million, which included $331 million in pre-tax insurance proceeds
for property damage, rebuild costs, and business interruption at
the Superior Refinery. The refinery is expected to resume
operations in 2020.
Throughput at the Lima Refinery averaged 105,900
bbls/day compared to 164,500 bbls/day in the fourth quarter of
2017, which takes into account a major scheduled turnaround that
began in mid-September 2018. The crude oil flexibility project to
increase heavy oil processing capacity from 10,000 bbls/day to
40,000 bbls/day by the end of 2019 is on track, with the 2018 work
scope successfully completed.
OFFSHORE
- Average production of 64,200 boe/day
- Operating netback of $58.48 per boe
- Asia Pacific operating netback of $67.42 per boe
- Atlantic operating netback of $23.19 per barrel
Asia
Pacific
ChinaSales gas production from the two producing fields at the
Liwan Gas Project averaged a record 403 mmcf/day, with associated
liquids averaging 19,200 bbls/day (197 mmcf/day and 9,300 bbls/day
Husky working interest). Realized gas pricing was $13.85 Cdn per
mcf, with liquids pricing of $69.76 Cdn per barrel.
At the Liuhua 29-1 field, three final wells are
scheduled to begin drilling in the first quarter of 2019.
Altogether, seven wells will be tied into the existing Liwan
infrastructure, with first gas expected around the end of 2020.
Target production from this third deepwater field at Liwan is 45
mmcf/day of gas and 1,800 bbls/day of liquids when fully ramped up,
reflecting Husky’s 75 percent working interest.
IndonesiaGas sales at the liquids-rich BD
Project averaged 91 mmcf/day, with liquids production of 7,700
bbls/day (38 mmcf/day and 2,800 bbls/day Husky working interest).
BD production was sold into the East Java market at contracted
rates for a realized gas price of $9.76 Cdn per mcf, with liquids
pricing of $96.83 Cdn per barrel.
Atlantic
West White Rose ProjectAt the West White Rose
Project, construction work on the drilling and wellhead platform,
topsides and living quarters is being advanced. First oil is
anticipated in 2022, with the project expected to reach peak
production of 75,000 bbls/day (52,500 bbls/day Husky working
interest) as development wells are drilled and brought online.
Two additional infill wells at the White Rose
field are expected to be brought online before mid-year 2019. These
are part of a program to offset reservoir declines at the White
Rose field and its satellite extensions until the startup of the
West White Rose Project.
SeaRose UpdateProduction at the SeaRose FPSO was
suspended on November 16 following an oil release from a flowline
connector in the South White Rose Extension Drill Centre.
Operations resumed at the end of January from the Central Drill
Centre, with production expected to continue ramping up through the
second quarter as additional subsea drill centres are brought
online.
2018 ANNUAL
HIGHLIGHTS
Integrated
Corridor
- Increased annual average production from Lloyd thermal bitumen
projects, Tucker and Sunrise to 124,200 bbls/day, compared to
119,100 bbls/day in 2017
- First oil ahead of schedule at the 10,000 bbls/day Rush Lake 2
thermal project
- Commenced construction of the 10,000 bbls/day thermal projects
at Dee Valley and Spruce Lake Central; completed site clearing at
Spruce Lake North
- Sanctioned the new 10,000 bbls/day Spruce Lake East thermal
project, with first production targeted around the end of 2021
- The Sunrise Energy Project reached and surpassed targeted
60,000 bbls/day (30,000 bbls/day Husky working interest)
- Record throughput of 75,600 bbls/day at the Lloydminster
Upgrader; EBITDA of $620 million, up 147 percent over 2017
- Increased Upgrading margin of $30.15 per barrel, compared to
$18.28 per barrel in 2017
- Strong margin capture in the Infrastructure and Marketing
segment, reflecting Husky’s long-term 75,000 bbls/day committed
export capacity on the Keystone pipeline
Offshore
- Successful oil exploration discoveries in both the Asia Pacific
and Atlantic regions
- Completed slip-forming on the West White Rose fixed wellhead
platform to a height of 46 metres
- Record sales gas production from the Liwan and BD projects
contributed to an overall annual Asia Pacific operating netback of
$67.79 per boe
- Increased working interest at Liuhua 29-1 to 75 percent from 49
percent, providing additional exposure to growing gas markets in
Asia
- Signed Production Sharing Contracts for two exploration blocks
offshore China in the Beibu Gulf
2018 RESERVES
REPLACEMENT
The proved reserves life index was 13.5 years, an increase from
11 years in 2017.
Total proved reserves before royalties at the end of 2018 were
1.5 billion boe. Probable reserves were 1.1 billion boe.
The 2018 proved reserves replacement ratio was
260 percent, excluding economic factors (255 percent including
economic factors). The average five-year proved reserves
replacement ratio was 144 percent, excluding economic factors (135
percent including economic factors). These take into account
acquisitions and the disposition in Western Canada of 62 million
boe of proved reserves in 2017 and 90 million boe of proved
reserves in 2016.
The five-year annual average proved reserves
replacement ratio continues to exceed the target of more than 130
percent.
Proved reserves additions and revisions of 279
million boe, including economic factors, take into account
additions related to two newly sanctioned Lloyd thermal bitumen
projects and improved performance in the existing projects, the
booking of proved reserves for the Liuhua 29-1 project, and future
development opportunities added at Sunrise, Lloyd thermal bitumen
projects, Ansell, Kakwa, Wembley and other fields, offset by
economic factors.
2019 GUIDANCE
UPDATE
Husky’s 2019 priorities are safe and reliable
operations and capital discipline.
Average annual production in 2019 is expected to
be in the range of 290,000-305,000 boe/day, with capital spending
anticipated to be in the range of $3.3-$3.5 billion.
Production reflects reductions associated with
the Government of Alberta’s mandatory oil production curtailments.
Husky believes that this abandonment of free market principles has
impacted investor confidence and created several business
challenges, including the Company’s ability to process and
transport its production to markets unimpeded, and profitably.
Curtailment rules disproportionately impact companies, like Husky,
with significant Downstream and midstream investments relative to
producers who have not made these investments.
Furthermore, the government’s curtailment
formula does not consider Husky’s production growth over the year
at Sunrise and Tucker, which are now at full capacity, and does not
consider costs related to marketing commitments, or the closure,
restart or early abandonment of wells and facilities.
Husky continues to engage with the Alberta
Energy Regulator and Alberta government to address the inequities,
costs and other unintended consequences of production
curtailment.
Production also takes into account the temporary
suspension of operations at the SeaRose FPSO in the first quarter
of 2019.
2019 CAPITAL
BUDGET ($ millions) |
|
PRODUCTION
SUMMARY |
|
|
|
|
|
Upstream |
2019
Guidance |
|
Crude Oil and Liquids
(mbbls/day) |
2019
Guidance |
Thermal and Oil Sands1 |
730 –
760 |
|
Thermal
and Oil Sands1 |
129 –
135 |
Conventional Heavy Oil1 |
100 – 110 |
|
Conventional Medium and Heavy
Oil1 |
29 – 31 |
Atlantic Region |
1,120 – 1,190 |
|
Atlantic Light Oil |
18 – 20 |
Asia
Pacific |
350 –
370 |
|
Western
Canada Resource Play Liquids |
20 –
21 |
Western Canada |
180 –
190 |
|
Asia
Pacific Light and natural gas liquids |
9 –
10 |
Total Upstream |
2,480 – 2,620 |
|
Total Crude Oil and Liquids |
205 – 217 |
|
|
|
|
|
Downstream |
|
|
Natural Gas (mmcf/day) |
|
Canada |
145 – 155 |
|
Canada |
297 – 307 |
U.S.2 |
545 –
580 |
|
Asia
Pacific |
210 –
220 |
Total Downstream |
690 – 735 |
|
Total Natural
Gas |
507 – 527 |
Corporate Capital |
130 – 145 |
|
Total
Upstream |
290 – 305 |
|
|
|
|
|
Total Capital
Investment2,3 |
3,300 –
3,500 |
|
|
|
Total Sustaining Capital |
$1.8B |
|
|
|
1 Includes reductions related to
government-mandated curtailments in Alberta.2Excludes Superior
Refinery rebuild capital of $199 million.3Excludes asset retirement
obligations, capitalized interest and administration.
2019 PLAN HIGHLIGHTS
- Capital spending in the range of $3.3-3.5 billion, including
approximately $1.8 billion in sustaining and corporate capital
- Mid-range average annual 2019 production of approximately
295,000 boe/day includes reductions related to government-mandated
curtailments in Alberta, and the temporary suspension of operations
at the SeaRose FPSO in the Atlantic region in the first quarter and
staged ramp-up through the second quarter
- Average Upstream operating cost target in the range of
$14.25-$15 per barrel; average Downstream operating cost target for
the Lloydminster Upgrader and U.S. refineries along the Integrated
Corridor in the $7.50-$8 per barrel range
Growth capital in 2019 includes progressing five
10,000 bbls/day Lloyd thermal projects in Saskatchewan to be
brought online through 2022, completing the crude oil flexibility
project at the Lima Refinery, development of the Liuhua 29-1 field
offshore China, and advancement of the West White Rose Project in
the Atlantic region.
Husky expects to achieve its targeted average
annual proved reserves replacement ratio of more than 130
percent.
STRATEGIC ASSET REVIEW
As part of its increasing focus on its core
heavy oil projects and Downstream assets in the Integrated Corridor
business, the Company has announced plans to market and potentially
sell its Canadian retail and commercial fuels business and the
Prince George Refinery.
No timeline has been determined for the closure
of any potential transactions, which were not reflected in the
five-year plan presented at Investor Day in May 2018.
2019 PLANNED MAINTENANCE AND TURNAROUNDS
Integrated Corridor
- Four-week partial turnaround at Sunrise in the second
quarter
- Four-week turnaround at the Prince George Refinery in the
second quarter
- Three-week turnaround at the Rainbow Lake processing facility
in the second quarter
- 45-day full shutdown at the Lima Refinery in the fourth quarter
for work related to the crude oil flexibility project, with
concurrent maintenance; anticipated throughput impact of 79,000
bbls/day over the quarter
- Planned turnaround at the Toledo Refinery
Offshore
- Seven-day maintenance at the Liwan Gas Project in the second
quarter
- 12-day maintenance at the BD Project in the first quarter
- Eight-day turnaround at the SeaRose FPSO in the third
quarter
- Two-week turnaround at the Terra Nova FPSO in the second
quarter
CORPORATE
DEVELOPMENTS
The Board of Directors has approved a quarterly
dividend of $0.125 per common share for the three-month period
ended December 31, 2018. The dividend will be payable April 1, 2019
to shareholders of record at the close of business on March 19,
2019.
Regular dividend payments on each of the
Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series
3, Series 5 and Series 7 – will be paid for the three-month period
ended March 31, 2019. The dividends will be payable on April 1,
2019 to holders of record at the close of business on March 19,
2019.
Share Series |
Dividend Type |
Rate (%) |
Dividend Paid
($/share) |
Series 1 |
Regular |
2.404 |
$0.15025 |
Series 2 |
Regular |
3.443 |
$0.21224 |
Series 3 |
Regular |
4.50 |
$0.28125 |
Series 5 |
Regular |
4.50 |
$0.28125 |
Series 7 |
Regular |
4.60 |
$0.28750 |
CONFERENCE CALL
A conference call will be held on Tuesday, Feb.
26 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss
Husky’s 2018 fourth quarter and annual results. CEO Rob Peabody,
COO Rob Symonds and CFO Jeff Hart will participate in the call.
To listen live:Canada and U.S. Toll Free:
1-855-327-6838Outside Canada and U.S.: 1-604-235-2082 |
To listen to a
recording (after 10 a.m. MT on Feb. 26):Canada and U.S.
Toll Free: 1-800-319-6413 Outside Canada and U.S.:
1-604-638-9010Passcode: 2892 Duration: Available March 26,
2019Audio webcast: Available for 90 days at huskyenergy.com |
Investor and Media
Inquiries:
Leo Villegas, Manager, Investor Relations403-513-7817
Mel Duvall, Senior Manager, Media & Issues403-513-7602
FORWARD-LOOKING STATEMENTS
Certain statements in this news release are
forward-looking statements and information (collectively,
“forward-looking statements”) within the meaning of the applicable
Canadian securities legislation, Section 21E of the United States
Securities Exchange Act of 1934, as amended, and Section 27A of the
United States Securities Act of 1933, as amended. The
forward-looking statements contained in this news release are
forward-looking and not historical facts.
Some of the forward-looking statements may be
identified by statements that express, or involve discussions as
to, expectations, beliefs, plans, objectives, assumptions or future
events or performance (often, but not always, through the use of
words or phrases such as “will likely result”, “are expected to”,
“will continue”, “is anticipated”, “is targeting”, “estimated”,
“intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”,
“objective”, “target”, “scheduled” and “outlook”). In
particular, forward-looking statements in this news release
include, but are not limited to, references to:
- with respect to the business, operations and results of the
Company generally: general strategic plans and growth strategies;
2019 production guidance, including guidance for specified areas
and product types; 2019 capital expenditure budget; 2019 average
Upstream and average Downstream operating cost targets; and
expectations regarding the 2019 average annual proved reserves
replacement ratio;
- with respect to the Company’s thermal developments: estimated
production and expected timing of first production from the Dee
Valley, Spruce Lake Central, Spruce Lake North, Spruce Lake East
and Edam Central projects; and the expected timing and duration of
the turnaround at Sunrise;
- with respect to the Company’s Western Canada resource plays,
the expected timing and duration of the turnaround at the Rainbow
Lake processing facility;
- with respect to the Company’s Offshore business in Asia
Pacific: the expected timing of commencement of drilling of
the remaining three wells at, and first gas production from,
Liuhua 29-1; target production from Liuhua 29-1 when fully
ramped up; and the expected timing and duration of maintenance at
the Liwan Gas Project and the BD Project;
- with respect to the Company’s Offshore business in Atlantic:
the expected timing of first production, and the expected volume of
peak production, at the West White Rose Project; the expected
timing that two additional infill wells will be brought online at
the White Rose field; the expected timing of production ramp-up at
the SeaRose FPSO; and expected timing and duration of turnarounds
at the SeaRose FPSO and the Terra Nova FPSO; and
- with respect to the Company’s Downstream operations: the
potential sale of non-core Downstream assets; the expected timing
that operations will resume at the Superior Refinery; the expected
timing of completion of the crude oil flexibility project at the
Lima Refinery; the expected timing and duration of the turnaround
at the Prince George Refinery; the expected timing and duration,
and the anticipated impact on throughput, of the full shutdown at
the Lima Refinery; and the planned turnaround at the Toledo
Refinery.
In addition, statements relating to “reserves”
are deemed to be forward-looking statements as they involve the
implied assessment based on certain estimates and assumptions that
the reserves described can be profitably produced in the future.
There are numerous uncertainties inherent in estimating quantities
of reserves and in projecting future rates of production and the
timing of development expenditures. The total amount or timing of
actual future production may vary from reserves and production
estimates.
Although the Company believes that the
expectations reflected by the forward-looking statements presented
in this news release are reasonable, the Company’s forward-looking
statements have been based on assumptions and factors concerning
future events that may prove to be inaccurate.
Those assumptions and factors are based on
information currently available to the Company about itself and the
businesses in which it operates. Information used in developing
forward-looking statements has been acquired from various sources,
including third-party consultants, suppliers and regulators, among
others.
Because actual results or outcomes could differ
materially from those expressed in any forward-looking statements,
investors should not place undue reliance on any such
forward-looking statements. By their nature, forward-looking
statements involve numerous assumptions, inherent risks and
uncertainties, both general and specific, which contribute to the
possibility that the predicted outcomes will not occur. Some of
these risks, uncertainties and other factors are similar to those
faced by other oil and gas companies and some are unique to the
Company.
The Company’s Annual Information Form for the
year ended December 31, 2018 and other documents filed with
securities regulatory authorities (accessible through the SEDAR
website www.sedar.com and the EDGAR website www.sec.gov) describe
some of the risks, material assumptions and other factors that
could influence actual results and are incorporated herein by
reference.
New factors emerge from time to time and it is
not possible for management to predict all of such factors and to
assess in advance the impact of each such factor on the Company’s
business or the extent to which any factor, or combination of
factors, may cause actual results to differ materially from those
contained in any forward-looking statement. The impact of any
one factor on a particular forward-looking statement is not
determinable with certainty as such factors are dependent upon
other factors, and the Company’s course of action would depend upon
management’s assessment of the future considering all information
available to it at the relevant time. Any forward-looking statement
speaks only as of the date on which such statement is made and,
except as required by applicable securities laws, the Company
undertakes no obligation to update any forward-looking statement to
reflect events or circumstances after the date on which such
statement is made or to reflect the occurrence of unanticipated
events.
NON-GAAP MEASURES
This news release contains references to the
terms “funds from operations”, “free cash flow”, “operating
netback”, “net debt”, “net debt to trailing funds from operations”,
“EBITDA” and “sustaining capital”. None of these measures is used
to enhance the Company’s reported financial performance or
position. These measures are useful complementary measures in
assessing the Company’s financial performance, efficiency and
liquidity. With the exception of funds from operations, free cash
flow and net debt, there are no comparable measures to these
non-GAAP measures under IFRS.
Funds from operations is a non-GAAP measure
which should not be considered an alternative to, or more
meaningful than, cash flow – operating activities as determined in
accordance with IFRS, as an indicator of financial performance.
Funds from operations is presented in the Company’s financial
reports to assist management and investors in analyzing operating
performance of the Company in the stated period. Funds from
operations equals cash flow – operating activities plus change in
non-cash working capital.
Funds from operations has been restated in the
second quarter of 2017 in order to be more comparable to similar
non-GAAP measures presented by other companies. Changes from prior
period presentation include the removal of adjustments for
settlement of asset retirement obligations and deferred revenue.
Prior periods have been restated to conform to current
presentation.
Free cash flow is a non-GAAP measure which
should not be considered an alternative to, or more meaningful
than, cash flow – operating activities as determined in
accordance with IFRS, as an indicator of financial performance.
Free cash flow is presented to assist management and
investors in analyzing operating performance by the business in the
stated period. Free cash flow equals funds from operations
less capital expenditures.
Free cash flow has been restated in the fourth
quarter of 2018 in order to be more comparable to similar non-GAAP
measures presented by other companies. Changes from prior period
presentation include the removal of investment in joint ventures.
Prior periods have been restated to conform to current
presentation.
The following table shows the reconciliation of
net earnings (loss) to funds from operations and free cash flow,
and related per share amounts, for the periods indicated:
|
|
Three months
ended |
|
12 months
ended |
|
Dec. 31 |
Sept. 30 |
Dec. 31 |
|
Dec. 31 |
Dec. 31 |
($
millions) |
2018 |
2018 |
2017 |
|
2018 |
2017 |
Net earnings |
216 |
545 |
672 |
|
1,457 |
786 |
Items not affecting cash: |
|
|
|
|
|
|
Accretion |
25 |
23 |
28 |
|
97 |
112 |
Depletion, depreciation, amortization and
impairment |
662 |
672 |
647 |
|
2,591 |
2,882 |
Inventory write-down to net realizable value |
60 |
- |
- |
|
60 |
- |
Exploration and evaluation expenses |
22 |
- |
- |
|
29 |
6 |
Deferred income taxes (recoveries) |
25 |
156 |
(360) |
|
396 |
(359) |
Foreign exchange loss (gain) |
1 |
(6) |
1 |
|
(6) |
(4) |
Stock-based compensation |
(50) |
40 |
25 |
|
44 |
45 |
Gain on sale of assets |
- |
- |
(13) |
|
(4) |
(46) |
Unrealized mark to market loss (gain) |
(16) |
(22) |
57 |
|
(150) |
56 |
Share of equity investment gain |
(16) |
(18) |
(1) |
|
(69) |
(61) |
Gain on insurance recoveries for damage to
property |
(253) |
- |
- |
|
(253) |
- |
Other |
2 |
(2) |
8 |
|
21 |
16 |
Settlement of asset retirement obligations |
(65) |
(45) |
(45) |
|
(181) |
(136) |
Deferred revenue |
(30) |
(25) |
(5) |
|
(100) |
(16) |
Distribution from joint ventures |
- |
- |
- |
|
72 |
25 |
Change in non-cash
working capital |
730 |
(35) |
337 |
|
130 |
398 |
Cash flow - operating activities |
1,313 |
1,283 |
1,351 |
|
4,134 |
3,704 |
Change in non-cash
working capital |
(730) |
35 |
(337) |
|
(130) |
(398) |
Funds from
operations |
583 |
1,318 |
1,014 |
|
4,004 |
3,306 |
Capital
expenditures |
(1,265) |
(968) |
(745) |
|
(3,578) |
(2,220) |
Free
cash flow |
(682) |
350 |
269 |
|
426 |
1,086 |
|
|
|
|
|
|
|
Weighted average number of common shares
outstanding |
1,005.1 |
1,005.1 |
1,005.1 |
|
1,005.1 |
1,005.3 |
Funds from operations |
|
|
|
|
|
|
Per common share - Basic
($/share) |
0.58 |
1.31 |
1.01 |
|
3.98 |
3.29 |
Operating netback is a common non-GAAP measure
used in the oil and gas industry. Management believes this
measure assists management and investors to evaluate the specific
operating performance by product at the oil and gas lease
level. Operating netback is calculated as gross revenue less
royalties, production and operating and transportation costs on a
per unit basis.
Net debt is a non-GAAP measure that equals the
sum of long-term debt, long-term debt due within one year and
short-term debt, less cash and cash equivalents. Net debt is
considered to be a useful measure in assisting management and
investors to evaluate the Company’s financial strength.
The following table shows the reconciliation of
net debt as at the dates indicated:
|
Dec. 31 |
Sept. 30 |
Dec. 31 |
($ millions) |
2018 |
2018 |
2017 |
Short-term debt |
200 |
200 |
200 |
Long-term debt due within one year |
1,433 |
388 |
- |
Long-term debt |
4,114 |
4,964 |
5,240 |
Cash and cash
equivalents |
(2,866) |
(2,916) |
(2,513) |
Net debt |
2,881 |
2,636 |
2,927 |
Net debt to trailing funds from operations is a
non-GAAP measure that equals net debt divided by the 12-month
trailing funds from operations as at December 31, 2018. Net
debt to trailing funds from operations is considered to be a useful
measure in assisting management and investors to evaluate the
Company’s financial strength.
EBITDA is a non-GAAP measure which should not be
considered an alternative to, or more meaningful than, "net
earnings (loss)" as determined in accordance with IFRS, as an
indicator of financial performance. EBITDA is presented to
assist management and investors in analyzing operating performance
by business in the stated period. EBITDA equals net
earnings (loss) plus finance expenses (income), provisions for
(recovery of) income taxes, and depletion, depreciation and
amortization.
Sustaining capital is the additional development
capital that is required by the business to maintain production and
operations at existing levels. Development capital includes the
cost to drill, complete, equip and tie-in wells to existing
infrastructure. Sustaining capital does not have any standardized
meaning and therefore should not be used to make comparisons to
similar measures presented by other issuers.
DISCLOSURE OF OIL AND GAS
INFORMATION
Unless otherwise indicated: (i) reserves
estimates have been prepared by internal qualified reserves
evaluators in accordance with the Canadian Oil and Gas Evaluation
Handbook, have an effective date of December 31, 2018 and represent
the Company’s working interest share; (ii) projected and
historical production volumes provided are gross, which represents
the total or the Company’s working interest share, as applicable,
before deduction of royalties; (iii) all Husky working interest
production volumes quoted are before deduction of royalties; and
(iv) historical production volumes provided are for the year ended
December 31, 2018.
The Company uses the term “barrels of oil
equivalent” (or “boe”), which is consistent with other oil and gas
companies’ disclosures, and is calculated on an energy equivalence
basis applicable at the burner tip whereby one barrel of crude oil
is equivalent to six thousand cubic feet of natural gas. The
term boe is used to express the sum of the total company products
in one unit that can be used for comparisons. Readers are
cautioned that the term boe may be misleading, particularly if used
in isolation. This measure is used for consistency with other oil
and gas companies and does not represent value equivalency at the
wellhead.
The Company uses the term “proved reserves life
index”, which is consistent with other oil and gas companies’
disclosures. The Company’s proved reserves life index for a
given period is determined by taking the Company’s total proved
reserves at the end of that period divided by the Company’s
upstream gross production for the same period. Readers are
cautioned that the term proved reserves life index may be
misleading, particularly if used in isolation. This measure is used
for consistency with other oil and gas companies and does not
reflect the actual life of the reserves.
The Company uses the term “reserves replacement
ratio”, which is consistent with other oil and gas companies’
disclosures. Reserves replacement ratios for a given period are
determined by taking the Company’s incremental proved reserve
additions for that period divided by the Company’s upstream gross
production for the same period. The reserves replacement ratio
measures the amount of reserves added to a company's reserves base
during a given period relative to the amount of oil and gas
produced during that same period. A company's reserves
replacement ratio must be at least 100 percent for the company to
maintain its reserves. The reserves replacement ratio only
measures the amount of reserves added to a company’s reserves base
during a given period. Reserves replacement ratios presented as
excluding economic factors exclude the impact that changing oil and
gas prices, inflation and regulations have on reserves amounts.
NOTE TO U.S. READERS
The Company reports its reserves and resources
information in accordance with Canadian practices and specifically
in accordance with National Instrument 51-101 Standards of
Disclosure for Oil and Gas Activities, adopted by the Canadian
securities regulators. Because the Company is permitted to prepare
its reserves and resources information in accordance with Canadian
disclosure requirements, it may use certain terms in that
disclosure that U.S. oil and gas companies generally do not include
or may be prohibited from including in their filings with the
SEC.
All currency is expressed in Canadian dollars
unless otherwise indicated.