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”,
“operating netback” and “EBITDA”. Please refer to “Non-GAAP
Measures” at the end of this news release.
Husky Energy (TSX: HSE) generated funds from operations of $959
million in the first quarter of 2019, compared to $895 million in
the first quarter of 2018. Net earnings were $328 million, compared
to $248 million in Q1 2018 and free cash flow was $147 million,
compared to $258 million in the first quarter of 2018. Cash flow
from operating activities, which includes changes in non-cash
working capital, was $545 million, compared to $529 million in Q1
2018.
“We delivered more funds from operations
compared to the first quarter of 2018, despite Alberta government
quotas on our oil production, and even with global oil prices
pretty much on par in Canadian dollar terms,” said CEO Rob
Peabody.
“The structural transformation of our business
over the past several years is paying off. We are now realizing
higher per-barrel margins across the Company.”
Peabody noted that while Husky’s Upstream
segment made a strong contribution to funds from operations as a
result of tighter Canadian heavy-light differentials, the largest
benefit was from U.S. refining margins. “This further demonstrates
the value of our Integrated Corridor business,” he said. “We can
capture value at any point along the Upstream-Downstream chain,
resulting in global pricing for most of our production.”
Husky further advanced its process safety and
asset integrity program in the first quarter with the appointment
of Peter Rosenthal as Senior Vice President of Safety and
Operations Integrity, reporting directly to the CEO.
FIRST QUARTER HIGHLIGHTS
- Funds from operations of $959 million, up 64% over the previous
quarter and 7% higher than Q1 2018
- Cash flow from operating activities of $545 million, compared
to $529 million in Q1 2018; the quarter saw an increase in working
capital driven by commodity prices, a seasonal increase in
inventories and business interruption insurance accruals related to
the Superior Refinery
- Net earnings of $328 million, up 52% over the previous quarter
and 32% higher than Q1 2018
- Capital spending of $812 million, primarily directed to
advancing Lloyd thermal bitumen projects and construction of the
West White Rose Project; 2019 capital guidance remains on
track
- Free cash flow of $147 million, compared to $258 million in Q1
2018
- Quarterly cash dividend of $0.125 per common share
declared
- Net debt of $3.4 billion, representing 0.8 times trailing 12
months funds from operations; senior unsecured notes offering
raised $750 million US for general corporate purposes, which may
include repaying debt maturing in 2019
- Upstream production of 285,200 barrels of oil equivalent per
day (boe/day) compared to 304,300 boe/day in Q4 2018, largely
reflecting the impact of mandatory Alberta production quotas and
limited production from the White Rose field; 2019 production
guidance remains on track
Integrated Corridor
- Downstream throughput of 333,600 barrels per day (bbls/day);
including record throughput at the Lima Refinery as a result of
efficiencies and optimizations
- Announced plans for the strategic review and potential sale of
non-core Downstream assets, including the Company’s Canadian retail
and commercial fuels business and the Prince George
Refinery
- 10,000 bbls/day Dee Valley Lloyd thermal project progressing
ahead of schedule, with first oil expected in Q4 2019
- Spruce Lake Central and Spruce Lake North Lloyd thermal
projects, representing an aggregate of 20,000 bbls/day, are
advancing towards first production in 2020
Offshore
- Production at the White Rose field offshore Newfoundland and
Labrador continues to ramp up following a temporary suspension of
operations in the fourth quarter of 2018
- Two additional infill wells at the White Rose field are in the
process of being tied in and are expected to be placed onto
production in the coming days
- Continued strong Asia Pacific operating netbacks of $68.33 per
boe
|
Three Months Ended |
|
|
Mar. 312019 |
Dec.
312018 |
Mar. 312018 |
|
Daily
production, before royalties |
|
|
|
|
Total equivalent production
(mboe/day) |
285 |
304 |
300 |
|
Crude oil
and natural gas liquids (mbbls/day) |
199 |
215 |
221 |
|
Natural gas
(mmcf/day) |
517 |
538 |
477 |
|
Upstream operating netback1,2
($/boe) |
27.69 |
9.42 |
24.37 |
|
Refinery and Upgrader
throughput (mbbls/day) |
334 |
287 |
398 |
|
Cash
flow – operating activities ($mm) |
545 |
1,313 |
529 |
|
Funds
from operations1 ($mm) |
959 |
583 |
895 |
|
Per common
share – Basic ($/share) |
0.95 |
0.58 |
0.89 |
|
Free
cash flow1 ($mm) |
147 |
(682) |
258 |
|
Net
earnings ($mm) |
328 |
216 |
248 |
|
Per common
share – Basic ($/share) |
0.32 |
0.21 |
0.24 |
|
Net
debt3 ($ billions) |
3.4 |
2.9 |
3.2 |
|
Dividend
per common share ($/share) |
0.125 |
0.125 |
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. |
FIRST QUARTER RESULTS
Upstream production averaged 285,200 boe/day,
compared to 300,400 boe/day in the first quarter of 2018. This
takes into account mandated Alberta government production quotas
and the ongoing ramp-up of operations at the White Rose field,
which resumed production at the end of January 2019. Production in
the Atlantic region averaged 7,600 bbls/day in the quarter compared
to 28,400 bbls/day a year ago.
Upstream operating netbacks averaged $27.69 per
boe, compared to $24.37 per boe in the first quarter of 2018,
reflecting tighter Canadian heavy oil differentials. Average
realized pricing for Upstream production was $47.20 per boe,
compared to $40.87 per boe in the year-ago period. Realized pricing
for oil and liquids averaged $49.14 per barrel, and natural gas
averaged $7.12 per thousand cubic feet (mcf).
Upstream operating costs averaged $16.30 per
boe, compared to $13.33 per boe in the first quarter of 2018. The
increase was due to a combination of factors, including Alberta
production quotas, reduced Atlantic volumes as the White Rose field
continues its production ramp up, and higher gas and electricity
costs in Western Canada.
Total Downstream throughput was 333,600 bbls/day
compared to 398,100 bbls/day in Q1 2018, which takes into account
the continued suspension of operations at the Superior
Refinery.
The Chicago 3:2:1 crack spread averaged $13.08
US per barrel compared to $12.84 US per barrel in Q1 2018.
The average realized U.S. Refining and Marketing
margin was $17.64 US per barrel of crude throughput, which reflects
a favourable first-in, first-out (FIFO) pre-tax inventory valuation
adjustment of $3.91 US per barrel. This compared to $8.51 US per
barrel a year ago, which included a favourable FIFO pre-tax
inventory valuation adjustment of $0.28 US per barrel.
The Upgrading realized margin was $21.24 per
barrel, down from $31.63 per barrel in the year-ago period, largely
due to tighter heavy oil differentials.
In the Infrastructure and Marketing segment,
EBITDA was $171 million compared to an EBITDA of $190 million in Q1
2018, primarily reflecting the value captured from the Company’s
long-term committed oil and gas export pipeline capacity and
storage assets.
Funds from operations were $959 million,
compared to $895 million in the first quarter of 2018. Capital
expenditures were $812 million, leading to free cash flow of $147
million. Net earnings were $328 million.
Capital spending included investments in Lloyd
thermal projects, the West White Rose Project, the Liuhua 29-1
field development, and the crude oil flexibility project at the
Lima Refinery.
INTEGRATED CORRIDOR
- Upstream average production of 231,500 boe/day
- Overall upstream operating netback of $21.03 per boe, compared
to $10.91 per boe in Q1 2018
- $30.89 per barrel netback from thermal operations
- Downstream throughput of 333,600 bbls/day
- Downstream upgrading/refining margin of $22.81 per barrel
- Infrastructure and Marketing realized margin of $167
million
Thermal
Production
The government production quota for Husky in
Alberta averaged out to be 86,000 bbls/day in the first quarter,
which resulted in the shut-in of approximately 20,000 bbls/day of
production. Impacts included:
- Production at the Sunrise Energy Project averaged 44,600
bbls/day (22,300 bbls/day Husky working interest) compared to
54,400 bbls/day (27,200 bbls/day Husky working interest) in the
fourth quarter of 2018 and 59,000 bbls/day in December 2018 (29,500
bbls/day Husky working interest).
- At Tucker, production averaged 25,000 bbls/day compared to
25,200 bbls/day in the fourth quarter of 2018 and 27,500 bbls/day
in December 2018.
Total thermal bitumen production from Lloyd
thermal projects, Tucker and Sunrise averaged about 130,300
bbls/day (Husky working interest), compared to 123,200 bbls/day
(Husky working interest) in the first quarter of 2018. Overall
operating costs at Sunrise, Tucker and 10 producing Lloyd thermal
projects were approximately $13.79 per barrel. Costs were up due to
higher gas and electricity prices as well as the impacts from the
production quota.
Five 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, first oil is expected in the fourth quarter of
2019
- At Spruce Lake Central, the central processing facility is
under construction with first production anticipated in the second
half of 2020
- At Spruce Lake North, first oil is planned around the end of
2020
- At Spruce Lake East, first production is expected around the
end of 2021
- At Edam Central, first production is anticipated in 2022
The Pikes Peak Lloyd thermal project was shut in
in February 2019 and will now be abandoned, after producing 78
million barrels over 36 years of operations.
Resource Plays
In the Ansell and Kakwa areas, eight wells were
drilled and six completed, with drilling focusing on liquids rich
wells in the Cardium and Spirit River formations. In the
liquids-rich Montney formation, three wells were drilled at Wembley
and one at Sinclair.
Downstream
Canadian throughput, including the Lloydminster
Upgrader and asphalt refinery, averaged 104,200 bbls/day. EBITDA
was $157 million.
U.S. refining throughput averaged 229,400
bbls/day, with record refining throughputs at the Lima Refinery
following a turnaround in Q4. Throughput at the Lima Refinery
averaged 171,400 bbls/day compared to 164,400 bbls/day in the first
quarter of 2018. The crude oil flexibility project to increase
heavy oil processing capacity from 10,000 bbls/day to 40,000
bbls/day is on pace for the end of 2019.
The U.S. refining segment recorded EBITDA of
$341 million, which included $113 million in pre-tax insurance
proceeds primarily for business interruption at the Superior
Refinery. The refinery rebuilding project is expected to begin this
fall, subject to regulatory approvals, with partial operations
targeted for late 2020.
OFFSHORE
- Average production of 53,700 boe/day
- Operating netback of $56.28 per boe
- China operating netback of $72.95 per boe
- Indonesia operating netback of $48.05 per boe
Asia
Pacific
ChinaSales gas production from the two producing fields at the
Liwan Gas Project averaged 369 million cubic feet per day
(mmcf/day), with associated liquids averaging 15,600 bbls/day (181
mmcf/day and 7,700 bbls/day Husky working interest). Realized gas
pricing was $14.35 Cdn per mcf, with liquids pricing of $69.11 Cdn
per barrel.
At the Liuhua 29-1 field, drilling of three
remaining wells is expected to be completed in the second 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% working interest.
IndonesiaSales gas production at the
liquids-rich BD Project averaged 89 mmcf/day, with liquids
production of 5,700 bbls/day (34 mmcf/day and 2,600 bbls/day Husky
working interest), reflecting a planned 12-day maintenance
completed in the first quarter.
BD production was sold at contracted rates for a
realized gas price of $9.88 Cdn per mcf, with liquids pricing of
$81.96 Cdn per barrel.
Atlantic
Overall average net production was approximately
7,600 bbls/day. This compares to 28,400 bbls/day in the same period
a year ago and reflects the suspension of operations at the White
Rose field in November 2018.
White Rose Field UpdateOperations resumed at the
end of January from the Central Drill Centre at the White Rose
field, with production expected to continue ramping up through the
second quarter as additional subsea drill centres are brought on
stream. Current production from the White Rose field is
approximately 5,000 bbls/day, Husky working interest.
Two additional infill wells at the White Rose
field are in the process of being tied in and are expected to be
placed onto production in the coming days.
West White Rose ProjectConstruction work on the
drilling and wellhead platform, topsides and living quarters
continues to progress, with first oil anticipated in 2022.
CORPORATE
DEVELOPMENTS
Husky announced the appointment of a new Senior
Vice President of Safety and Operations Integrity. Peter Rosenthal
reports directly to the CEO and will oversee process and
occupational safety, operations integrity and emergency response.
He has deep experience in process safety and risk management, with
nearly 30 years of industry experience.
During the quarter, Husky raised $750 million US
in a senior unsecured notes offering with the proceeds being used
for general corporate purposes, which may include, among other
things, the repayment of certain outstanding debt securities
maturing in 2019.
The Board of Directors has approved a quarterly
dividend of $0.125 per common share for the three-month period
ended March 31, 2019. The dividend will be payable July 2, 2019 to
shareholders of record at the close of business on June 10,
2019.
Regular dividend payments on each of the
Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series
3, Series 5 and Series 7 – will be paid for the three-month period
ended June 30, 2019. The dividends will be payable on July 2, 2019
to holders of record at the close of business on June 10, 2019.
Share Series |
Dividend
Type |
Rate (%) |
Dividend Paid
($/share) |
Series 1 |
Regular |
2.404 |
$0.15025 |
Series 2 |
Regular |
3.443 |
$0.21267 |
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 Friday, April
26 at 8 a.m. Mountain Time (10 a.m. Eastern Time) to discuss
Husky’s 2019 first quarter 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: 1-800-319-4610Outside
Canada and U.S.: 1-604-638-5340 |
To listen to a
recording (after 9 a.m. MT on April 26):Canada and U.S.
Toll Free: 1-800-319-6413 Outside Canada and U.S.:
1-604-638-9010Passcode: 3076 Duration: Available until May
26, 2019Audio webcast: Available for 90 days at
www.huskyenergy.com |
Following the conference call, the Company will
hold its Annual Meeting of Shareholders at 10:30 a.m. (Mountain
Time) in the Performance Hall at Studio Bell, 850 4th Street S.E.,
Calgary, Alberta.
A live webcast of the meeting will be available
at www.huskyenergy.com under Investor Relations. The archived
webcasts of the conference call and the meeting will be available
for approximately 90 days.
Investor and Media
Inquiries:
Leo Villegas, Senior 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; production guidance
remaining on track; and the use of proceeds of the senior unsecured
notes offering;
- 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;
- 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; and target production from
Liuhua 29-1 when fully ramped up.
- with respect to the Company’s
Offshore business in Atlantic: expectations regarding the
ramp-up of production at the White Rose field; expected timing for
two additional infill wells at the White Rose field to be placed
onto production; and the expected timing of first oil at the West
White Rose Project; and
- with respect to the Company’s
Downstream operations: the potential sale of non-core
Downstream assets; the expected timing of completion of the crude
oil flexibility project at the Lima Refinery; the expected timing
of commencement of the rebuild of the Superior Refinery; and the
expected timing of resumption of partial operations at the Superior
Refinery.
There are numerous uncertainties inherent in
projecting future rates of production and the timing of development
expenditures. The total amount or timing of actual future
production may vary from 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”, “net debt”, “net
debt to trailing funds from operations”, “operating netback” and
“EBITDA”. 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.
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 was 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 |
|
Mar.
31 |
Dec.
31 |
Mar.
31 |
($ millions) |
2019 |
2018 |
2018 |
Net earnings |
328 |
216 |
248 |
Items not affecting
cash: |
|
|
|
Accretion |
27 |
25 |
24 |
Depletion, depreciation,
amortization and impairment |
630 |
662 |
618 |
Inventory write-down to
net realizable value |
- |
60 |
- |
Exploration and evaluation
expenses |
- |
22 |
- |
Deferred income taxes |
43 |
25 |
77 |
Foreign exchange loss
(gain) |
(12) |
1 |
1 |
Stock-based
compensation |
7 |
(50) |
21 |
Gain on sale of
assets |
(2) |
- |
(4) |
Unrealized mark to market
loss (gain) |
57 |
(16) |
(86) |
Share of equity investment
gain |
(22) |
(16) |
(9) |
Gain on insurance
recoveries for damage to property |
- |
(253) |
- |
Other |
(9) |
2 |
2 |
Settlement of asset
retirement obligations |
(72) |
(65) |
(49) |
Deferred revenue |
(16) |
(30) |
(20) |
Distribution from joint
ventures |
- |
- |
72 |
Change in non-cash working capital |
(414) |
730 |
(366) |
Cash flow - operating
activities |
545 |
1,313 |
529 |
Change in non-cash working capital |
414 |
(730) |
366 |
Funds from operations |
959 |
583 |
895 |
Capital expenditures |
(812) |
(1,265) |
(637) |
Free cash flow |
147 |
(682) |
258 |
|
|
|
|
Weighted average number of
common shares outstanding |
1,005.1 |
1,005.1 |
1,005.1 |
Funds from operations |
|
|
|
Per common
share - Basic ($/share) |
0.95 |
0.58 |
0.89 |
Net debt is a non-GAAP measure that equals the
sum of long-term debt, long-term debt due within one year and
short-term debt, less cash and cash equivalents. Net debt is
considered to be a useful measure in assisting management and
investors to evaluate the Company’s financial strength.
The following table shows the reconciliation of net debt as at
the dates indicated:
|
Mar. 31 |
Dec. 31 |
Mar. 31 |
($ millions) |
2019 |
2018 |
2018 |
Short-term debt |
200 |
200 |
200 |
Long-term debt due within one year |
1,803 |
1,433 |
- |
Long-term debt |
4,661 |
4,114 |
5,343 |
Cash and cash
equivalents |
(3,245) |
(2,866) |
(2,301) |
Net debt |
3,419 |
2,881 |
3,242 |
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 March 31, 2019. 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.
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.
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.
DISCLOSURE OF OIL AND GAS
INFORMATION
Unless otherwise indicated: (i) 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; (ii) all Husky working
interest production volumes quoted are before deduction of
royalties; and (iii) 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.
All currency is expressed in Canadian dollars
unless otherwise indicated.