CALGARY, May 9, 2018 /CNW/ -
OIL AND GAS OPERATIONS
- Paramount's sales volumes averaged 92,203 Boe/d in the first
quarter of 2018 compared to 16,163 Boe/d in the first quarter of
2017. Third-party outages, due to unscheduled downtime and
extremely cold weather conditions, impacted production by
approximately 6,000 Boe/d in the quarter.
- Montney wells at Karr are
maintaining higher condensate rates for longer periods after
initial start-up. To maximize cash flows, the Company is
prioritizing condensate production and fully utilizing liquids
handling capacity, which resulted in natural gas production at Karr
being curtailed by approximately 2,400 Boe/d in the first quarter
of 2018.
- Liquids sales volumes increased to 33,689 Bbl/d in the first
quarter of 2018 compared to 7,603 Bbl/d in the first quarter of
2017. Liquids revenue was $183.9
million, 68 percent of total revenue.
- Adjusted funds flow was $97.6
million in the first quarter of 2018 compared to
$28.0 million in the first quarter of
2017.
- In the Grande Prairie Region, activities focused on Paramount's
Montney developments, with
drilling operations carried out at two five-well pads at Karr and
an eleven-well pad at Wapiti.
- In the Kaybob Region, development activities focused on
drilling operations for a four-well Smoky Duvernay pad, a five-well
South Duvernay pad and six Montney
Oil wells drilled on two pads.
- In the Central Alberta and
Other Region, a new Duvernay well
was drilled at Willesden Green.
- Exploration and development capital for the first quarter of
2018 totaled $131.6 million,
primarily related to drilling and completion programs and
facilities projects in the Grande
Prairie and Kaybob Regions.
- First quarter 2018 capital spending included $42.1 million related to 2019 projects at Wapiti
and Karr. The Wapiti growth play will add material production and
cash flows in mid-2019.
- As a result of liquids handling constraints at Karr, delays in
the anticipated startup of new Kaybob wells, the deferral of new
production at the non-operated Birch property and unplanned
third-party outages in the first quarter, the Company expects sales
volumes to average approximately 92,500 Boe/d (37 percent liquids)
in 2018.
- Sales volumes are anticipated to be three to five percent lower
in the second and third quarters of 2018 compared to the first
quarter, primarily due to processing facility outages. Sales
volumes will increase in the fourth quarter as facility constraints
are alleviated and new wells are brought on production.
- The Company's 2018 capital budget remains unchanged at
$600 million.
CORPORATE
- In April 2018, the Company
redeemed all $300 million principal
amount of its 7.25% senior unsecured notes. The redemption was
funded from the Company's expanded $1.2
billion bank credit facility.
- In December 2017, Paramount
implemented a normal course issuer bid. To date, the Company has
purchased and cancelled 1,454,100 common shares under the program
at a total cost of $27.4 million.
- The Company has commenced a disposition process for its fee
simple and royalty lands in southern Alberta and expects the disposition to be
completed in the third quarter of 2018. The Company continues to
pursue other non-core dispositions.
REVIEW OF OPERATIONS
Paramount's sales volumes averaged 92,203 Boe/d in the first
quarter of 2018 compared to 16,163 Boe/d in the first quarter of
2017, with liquids volumes increasing to 33,689 Bbl/d compared to
7,603 Bbl/d in the same period in 2017. Production in the quarter
was impacted by liquids production management at Karr and
production disruptions due to third-party outages resulting from
unscheduled downtime and extremely cold weather conditions.
Paramount's netback was $134.5
million in the first quarter of 2018, over four times the
first quarter 2017 netback of $31.7
million. Adjusted funds flow was $97.6 million compared to $28.0 million in the same quarter in 2017.
The Company's cost structure is comparable to other
liquids-focused producers in western Canada. As a liquids-focused producer,
Paramount's operating costs include liquids handling expenses that
are not applicable to dry natural gas production. Operating costs
were $11.12 per Boe in the first
quarter due to maintenance work and lower sales volumes. The
Company is continuing to streamline its field operations, including
consolidating field offices, optimizing field staff and contract
operators and rationalizing software and service contracts.
Exploration and development capital for the first quarter of
2018 totaled $131.6 million,
primarily related to the 2018 drilling and completion programs and
facilities projects in the Grande
Prairie and Kaybob Regions. Approximately $42.1 million or 32 percent of first quarter
capital spending was related to projects at Wapiti and Karr that
will add new production in 2019.
GRANDE PRAIRIE
REGION
Sales volumes in the Grande Prairie Region in the first quarter
of 2018 averaged 28,398 Boe/d, 51 percent of which were liquids. In
addition to a 2,400 Boe/d curtailment of natural gas volumes at
Karr to maximize condensate production, unplanned third-party
facility and pipeline outages reduced Grande Prairie Region sales
volumes by approximately 2,000 Boe/d in the first quarter.
Exploration and development capital in the Grande Prairie Region
was $74.3 million in the first
quarter of 2018. Development activities focused on drilling
operations at two five-well pads at Karr (the 1-2 and 4-24 pads)
and an eleven-well pad at Wapiti (the 9-3 pad). First quarter
capital expenditures include approximately $11 million of additional costs as a result of
difficulties encountered with a well completion at Karr.
Karr
Condensate to gas ratios, and wellhead condensate rates, from
Montney wells at Karr continue to
exceed expectations. New wells are maintaining higher condensate
rates for longer periods after initial start-up, which resulted in
higher than expected per-well condensate production in the first
quarter of 2018. To maximize cash flows, the Company is
prioritizing condensate production at the Company's 6-18
dehydration and compression facility (the ʺ6-18 Facilityʺ), fully
utilizing liquids handling capacity and managing natural gas
production by applying a low drawdown (choke management) to
the wellhead. This resulted in the curtailment of approximately
2,400 Boe/d of natural gas production in the first quarter of
2018.
Wells from the 2016/2017 capital program are being produced at
restricted rates and in some cases shut-in as the Company pursues a
number of liquids handling debottlenecking initiatives. Production
volumes from the existing production base and the new 1-2 pad,
which is scheduled to be brought on production in the third
quarter, are expected to continue to fully utilize Karr area
liquids handling capacity for the remainder of the year. As a
result, the Company is deferring the completion and startup of the
five wells on the new 4-24 pad until 2019.
Paramount is adding liquids handling expansion projects to the
2018 Karr capital program to debottleneck liquids processes at the
6-18 Facility and add incremental liquids gathering capacity. This
will allow additional liquids volumes to be delivered to the
downstream third-party facility (the ʺSimonette Facilityʺ) that
processes Company production volumes. The Company is also
installing additional liquids loading equipment at the 6-18
Facility and at pad sites upstream to increase trucking capacity.
These projects are expected to be completed by the end of 2018 at a
cost of approximately $10
million.
The Company has also added a water disposal well and related
facilities to the 2018 Karr capital program, at a cost of
approximately $9 million. This
project will provide operating cost savings by reducing water
trucking and disposal costs.
The expansion of the 6-18 Facility from 80 MMcf/d to 100 MMcf/d
is proceeding on schedule. The compression and dehydration
equipment for the expansion has been installed and the expansion
will be tied in and commissioned as the liquids handling
debottlenecking projects are completed and the incremental natural
gas capacity is required. This incremental natural gas capacity,
together with the Company's liquids handling enhancements, will
enable the Company to further increase overall production in
2019.
Production at Karr was shut-in for approximately three days at
the beginning of May 2018 for the
tie-in of a condensate stabilizer expansion at the Simonette
Facility.
To support growth at Karr, the Company has sanctioned the
construction of a Company-owned processing facility to be built
alongside the current 6-18 dehydration and compression facility.
The project will add 50 MMcf/d of natural gas processing capacity
and 30,000 Bbl/d of condensate stabilization capacity. This new
processing facility is scheduled to be commissioned in the second
half of 2020.
Sales volumes and netbacks at Karr are summarized as
follows:
Karr
|
|
|
Q1
2018
|
Q1
2017
|
Change
%
|
Sales
volumes
|
|
|
|
|
|
Natural gas
(MMcf/d)
|
|
63.1
|
23.9
|
164
|
|
Condensate and oil
(Bbl/d)
|
|
11,399
|
5,231
|
118
|
|
Other NGLs
(Bbl/d)
|
|
1,192
|
428
|
179
|
|
Total
(Boe/d)
|
|
23,105
|
9,642
|
140
|
|
%
liquids
|
|
54%
|
59%
|
|
Netback
|
|
$/Boe
|
($
millions)
|
$/Boe
|
($
millions)
|
Change
%
($
millions)
|
|
Petroleum and natural
gas sales
|
|
43.97
|
91.4
|
44.19
|
38.3
|
139
|
|
Royalties
|
|
(1.27)
|
(2.6)
|
(1.45)
|
(1.3)
|
100
|
|
Operating
expense
|
|
(8.19)
|
(17.0)
|
(8.55)
|
(7.4)
|
130
|
|
Transportation and
NGLs processing
|
|
(4.17)
|
(8.7)
|
(4.44)
|
(3.8)
|
129
|
|
|
30.34
|
63.1
|
29.75
|
25.8
|
145
|
Karr area production currently represents approximately 25
percent of Paramount's production. The Company's cash flows benefit
from the liquids-rich product mix at Karr, which generates higher
per-unit revenues. Per-unit operating costs at Karr are also lower
due to production being focused at multi-well pads, which are more
efficient to produce. As Paramount continues to grow production at
Karr and bring on its new Montney
development at Wapiti, these liquids-focused areas will contribute
a higher proportion of the Company's sales volumes and cash
flows.
The table below summarizes the performance from 27 Montney wells
from the Company's 2016/2017 development program:
Well
|
|
Peak
30-Day Total
(1)
|
Peak
30-Day Condensate
(1)
|
Peak
30-Day Condensate
|
Days on
Production
|
Cumulative
Production (2)
|
|
|
(Boe/d)
|
(Bbl/d)
|
(%)
|
|
(MBoe)
|
00/04-07-065-05W6/00
|
|
2,555
|
1,815
|
71%
|
443
|
565
|
02/04-07-065-05W6/00
|
|
2,847
|
2,176
|
76%
|
413
|
658
|
02/01-12-065-06W6/00
|
|
2,637
|
1,795
|
68%
|
400
|
493
|
00/09-32-065-04W6/00
|
|
2,163
|
1,401
|
65%
|
330
|
508
|
00/16-32-065-04W6/00
|
|
2,127
|
1,263
|
59%
|
310
|
532
|
00/01-12-065-06W6/00
|
|
2,221
|
1,533
|
69%
|
290
|
336
|
00/03-22-066-05W6/00
|
|
1,955
|
946
|
48%
|
267
|
307
|
00/04-06-066-04W6/00
|
|
1,820
|
900
|
49%
|
268
|
377
|
02/16-24-066-05W6/00
|
|
1,345
|
694
|
52%
|
267
|
267
|
02/04-06-066-04W6/00
|
|
2,053
|
1,414
|
69%
|
265
|
381
|
00/03-06-066-04W6/00
|
|
1,845
|
942
|
51%
|
264
|
425
|
00/15-14-065-06W6/00
|
|
2,627
|
1,341
|
51%
|
248
|
476
|
00/16-24-066-05W6/00
|
|
1,356
|
710
|
52%
|
243
|
277
|
00/04-34-065-05W6/00
|
|
2,143
|
994
|
46%
|
257
|
371
|
00/01-33-065-05W6/00
|
|
1,918
|
805
|
42%
|
255
|
347
|
02/09-32-065-04W6/00
|
|
1,771
|
1,042
|
59%
|
235
|
270
|
02/16-14-065-06W6/00
|
|
2,230
|
1,350
|
61%
|
203
|
346
|
00/08-32-065-04W6/00
|
|
1,860
|
1,176
|
63%
|
180
|
286
|
00/13-14-065-06W6/00
|
|
1,715
|
1,060
|
62%
|
177
|
227
|
02/15-14-065-06W6/00
|
|
1,921
|
1,235
|
64%
|
133
|
226
|
02/14-14-065-06W6/00
|
|
1,796
|
1,218
|
68%
|
130
|
213
|
02/02-25-065-05W6/02
|
|
1,913
|
1,146
|
60%
|
127
|
205
|
03/01-25-065-05W6/00
|
|
1,507
|
890
|
59%
|
123
|
159
|
02/03-25-065-05W6/00
|
|
1,818
|
1,013
|
56%
|
116
|
197
|
00/03-25-065-05W6/00
|
|
1,610
|
1,007
|
63%
|
78
|
115
|
00/02-25-065-05W6/00
|
|
1,838
|
1,076
|
59%
|
77
|
123
|
00/14-14-065-06W6/00
|
|
1,521
|
1,044
|
69%
|
49
|
66
|
Average
|
|
1,963
|
1,185
|
60%
|
228
|
|
(1)
|
Peak 30 Day is the
highest daily average production rate over a 30-day consecutive
period for an individual well, measured at the wellhead. Natural
gas sales volumes are approximately 10 percent lower and stabilized
condensate sales volumes are approximately 15 percent lower due to
shrinkage. Excludes days when the well did not produce. The
production rates and volumes shown are 30 day peak rates over a
short period of time and, therefore, are not necessarily indicative
of average daily production, long-term performance or of ultimate
recovery from the wells. Certain of the wells were produced at
restricted rates due to facility and gathering system
constraints.
|
(2)
|
Cumulative production
for an individual well measured at the wellhead to April 30, 2018.
Excludes days when the well did not produce. Natural gas sales
volumes are approximately 10 percent lower and stabilized
condensate sales volumes are approximately 15 percent lower due to
shrinkage.
|
Wapiti
Paramount is currently producing legacy Montney wells at Wapiti through an existing
third-party processing facility. Sales volumes at Wapiti for the
first quarter of 2018 were approximately 500 Boe/d.
Drilling operations for the 2018 capital program commenced in
January with 11 (11.0 net) of the planned 23 (23.0 net)
Montney wells spud. These 11 wells
are located on the 9-3 pad and are being drilled with two Fox
Drilling rigs working simultaneously. The 9-3 pad is scheduled to
be completed and brought on production through a new 150 MMcf/d
third-party processing facility, which the operator plans to
commission in mid-2019. These new Wapiti Montney wells are similar
in design to the recent Karr development wells and are expected to
have similar production profiles.
KAYBOB REGION
Sales volumes in the Kaybob Region in the first quarter of 2018
averaged 41,843 Boe/d, including 12,650 Bbl/d of liquids.
Production disruptions as a result of unplanned third-party
pipeline and facility outages and freeze offs due to extremely cold
weather conditions reduced first quarter sales volumes by
approximately 3,500 Boe/d. Exploration and development capital in
the Kaybob Region was $50.0 million
in the first quarter of 2018.
In April 2018, approximately 4,000
Boe/d of Kaybob area production was shut-in as a result of a
scheduled four-week turnaround at a third-party facility that
processes the Company's production. The downstream facility is
expected to be back in service in mid-May and the Company will
restart affected wells.
Kaybob Smoky Duvernay
The Company is drilling a four (4.0 net) well pad at Kaybob
Smoky Duvernay in 2018. The first well on the pad was spud in late
November 2017 and all four wells were
rig released by the end of April
2018. Wells on this pad are scheduled to be completed in the
summer and brought on production through the Paramount operated
Kaybob Smoky natural gas plant. The expansion of the Kaybob
Smoky plant is in progress with start-up anticipated in the third
quarter of 2018.
Kaybob South Duvernay
The Company's 2018 capital plan at the Kaybob South Duvernay
development includes 11 (5.6 net) wells on two multi-well pads.
Five of the wells are scheduled to be completed in 2018, with the
remaining wells to be completed in 2019. The first five-well pad
was spud in November 2017, with all
five wells being rig released in the first quarter of 2018. This
pad is scheduled to be brought on production in the third quarter
of 2018, through a third-party operated natural gas plant.
Kaybob Montney Oil
First quarter 2018 sales volumes at the Kaybob Montney Oil
property were 8,965 Boe/d, approximately 62 percent liquids. Six
wells in the Company's 2018 capital program have been completed and
brought on production to date. Drilling and completion activities
are continuing and additional wells from the program will be
brought on production throughout the year.
The total cost to drill, complete and tie-in certain Kaybob
Montney Oil wells has increased compared to the original budget. As
a consequence, the Company has removed four wells from the 21-well
2018 capital program.
CENTRAL ALBERTA AND OTHER
REGION
Sales volumes in the Central
Alberta and Other Region in the first quarter of 2018
averaged 21,962 Boe/d. Third-party outages and cold weather reduced
sales volumes in the Region by approximately 500 Boe/d. The
operator of the Birch property in northeast British Columbia has delayed the startup of
new production until 2019, which is expected to impact Paramount's
2018 average sales volumes by approximately 1,100 Boe/d.
Total capital expenditures in the Central Alberta and Other Region were
$7.3 million in the first quarter of
2018. Development activities focused on a Duvernay well at Willesden Green. The well was
rig released in April 2018 and is
scheduled to be completed and brought on production in the third
quarter.
As the Company achieved its land tenure objective with the
initial well in the program, Paramount has removed a second well
planned for Willesden Green in 2018. The Company is reallocating
capital to optimization projects that are expected to recover
incremental reserves from existing wells.
The Company has commenced a disposition process for its fee
simple and royalty lands in southern Alberta and expects the disposition to be
completed in the third quarter of 2018. There is minimal production
associated with these lands. The Company continues to pursue other
non-core dispositions.
OUTLOOK
As a result of: (i) prioritizing condensate production and
delays in starting up new production at Karr due to liquids
handling constraints, (ii) delays in the anticipated startup of new
Kaybob wells, (iii) the deferral of approximately 1,100 Boe/d of
new production at the non-operated Birch property and (iv)
approximately 6,000 Boe/d (1,500 Boe/d annualized) of unplanned
third-party outages in the first quarter, the Company expects sales
volumes to average approximately 92,500 Boe/d (37 percent liquids)
in 2018.
Paramount's sales volumes are anticipated to be three to five
percent lower in the second and third quarters of 2018 compared to
the first quarter of 2018. The Company's production in the second
quarter is being impacted by third-party outages at Kaybob and
Karr. In the third quarter, a scheduled turnaround will also impact
production at Karr, and the Company is completing a turnaround at
its 8-9 natural gas processing facility in Kaybob, which will
curtail production and delay the startup of new Duvernay wells. Sales volumes will
increase in the fourth quarter as facility constraints are
alleviated and new wells from the 2018 capital program are brought
on production.
The Company continues to monitor natural gas prices and may
shut-in properties on a short-term basis through the summer months.
As a result of a large proportion of the Company's operating
costs being fixed, the revision to forecast sales volumes is
expected to result in average operating costs of approximately
$11.00 per Boe in 2018.
The Company's 2018 capital budget remains unchanged at
$600 million, including exploration,
optimization and maintenance programs and excluding acquisitions,
divestitures and abandonment and reclamation activities.
OPERATING AND
FINANCIAL RESULTS (1)
|
|
|
|
|
|
($ millions,
except as noted)
|
|
|
|
|
|
|
Q1
2018
|
Q1 2017
|
%
Change
|
Sales volumes
(Boe/d)
|
|
|
|
|
|
|
Grande
Prairie
|
|
28,398
|
|
14,408
|
97
|
|
Kaybob
|
|
41,843
|
|
218
|
NM
|
|
Central Alberta and
Other
|
|
21,962
|
|
1,537
|
NM
|
Total
|
|
92,203
|
|
16,163
|
470
|
Netback
|
$/Boe
(3)
|
|
$/Boe
(3)
|
|
% Change
$/Boe
|
|
Natural gas
revenue
|
2.59
|
81.9
|
3.55
|
16.4
|
(27)
|
|
Condensate and oil
revenue
|
70.10
|
160.2
|
61.75
|
35.3
|
14
|
|
Other NGLs revenue
(2)
|
31.68
|
23.7
|
23.69
|
2.7
|
34
|
|
Royalty and sulphur
revenue
|
─
|
4.0
|
─
|
0.3
|
─
|
Petroleum and
natural gas sales
|
32.51
|
269.8
|
37.61
|
54.7
|
(14)
|
|
Royalties
|
(1.93)
|
(16.0)
|
(1.39)
|
(2.0)
|
39
|
|
Operating
expense
|
(11.12)
|
(92.3)
|
(10.22)
|
(14.9)
|
9
|
|
Transportation and
NGLs processing (4)
|
(3.26)
|
(27.0)
|
(4.22)
|
(6.1)
|
(23)
|
Netback
|
16.20
|
134.5
|
21.78
|
31.7
|
(26)
|
|
|
|
|
|
|
Exploration and
development capital (5)
|
|
|
|
|
|
|
Grande
Prairie
|
|
74.3
|
|
131.5
|
(43)
|
|
Kaybob
|
|
50.0
|
|
─
|
100
|
|
Central Alberta and
Other
|
|
7.3
|
|
14.3
|
(49)
|
Total
|
|
131.6
|
|
145.8
|
(10)
|
|
|
|
|
|
|
Net income
(loss)
|
|
(81.1)
|
|
20.7
|
NM
|
|
per share –
diluted ($/share)
|
|
(0.61)
|
|
0.19
|
|
|
|
|
|
|
|
Adjusted funds
flow
|
|
97.6
|
|
28.0
|
249
|
|
per share –
diluted ($/share)
|
|
0.73
|
|
0.26
|
|
|
|
|
|
|
|
Total
assets
|
|
4,978.0
|
|
2,010.3
|
148
|
|
|
|
|
|
|
Net debt
(cash)
|
|
705.7
|
|
(442.6)
|
NM
|
|
|
|
|
|
|
Common shares
outstanding (thousands)
|
|
133,662
|
|
106,142
|
26
|
|
|
|
|
|
|
(1)
|
Readers are referred
to the advisories concerning Non-GAAP Measures and Oil and Gas
Measures and Definitions in the Advisories section of this
document.
|
(2)
|
Other NGLs include
ethane, propane and butane.
|
(3)
|
Natural gas revenue
shown per Mcf.
|
(4)
|
Includes downstream
natural gas, NGLs and oil transportation costs and NGLs
fractionation costs incurred by the Company.
|
(5)
|
Excludes land and
property acquisitions and spending related to corporate
assets.
|
NM
|
Not
meaningful
|
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused
Canadian energy company that explores for and develops both
conventional and unconventional petroleum and natural gas
resources, including long-term strategic exploration and
pre-development plays, and holds a portfolio of investments in
other entities. The Company's principal properties are located in
Alberta and British Columbia. Paramount's Class A common
shares are listed on the Toronto Stock Exchange under the symbol
"POU".
Paramount's first quarter 2018 results, including Management's
Discussion and Analysis and the Company's Consolidated Financial
Statements can be obtained at:
http://files.newswire.ca/1509/paramount0509.pdf.
This information will also be made available through Paramount's
website at www.paramountres.com and on SEDAR at www.sedar.com.
Advisories
Forward-looking Information
Certain statements in this document constitute forward-looking
information under applicable securities legislation.
Forward-looking information typically contains statements with
words such as "anticipate", "believe", "estimate", "will",
"expect", "plan", "schedule", "intend", "propose", or similar words
suggesting future outcomes or an outlook. Forward-looking
information in this document includes, but is not limited to:
- projected production, sales volumes and cash flows and the
timing thereof;
- forecast capital expenditures and operating costs;
- exploration, development, and associated operational plans and
strategies;
- projected timelines for, and the estimated costs of,
constructing and starting up new and expanded processing
facilities;
- the projected availability of third party processing
facilities; and
- general business strategies and objectives.
Such forward-looking information is based on a number of
assumptions which may prove to be incorrect. Assumptions have been
made with respect to the following matters, in addition to any
other assumptions identified in this document:
- future natural gas and liquids prices;
- royalty rates, taxes and capital, operating, general &
administrative and other costs;
- foreign currency exchange rates and interest rates;
- general business, economic and market conditions;
- the ability of Paramount to obtain the required capital to
finance its exploration, development and other operations and meet
its commitments and financial obligations;
- the ability of Paramount to obtain equipment, services,
supplies and personnel in a timely manner and at an acceptable cost
to carry out its activities;
- the ability of Paramount to secure adequate product processing,
transportation, de-ethanization, fractionation, and storage
capacity on acceptable terms;
- the ability of Paramount to market its natural gas and liquids
successfully to current and new customers;
- the ability of Paramount and its industry partners to obtain
drilling success (including in respect of anticipated production
volumes, reserves additions, liquids yields and resource
recoveries) and operational improvements, efficiencies and results
consistent with expectations;
- the timely receipt of required governmental and regulatory
approvals; and
- anticipated timelines and budgets being met in respect of
drilling programs and other operations (including well completions
and tie-ins and the construction, commissioning and start-up of new
and expanded facilities).
Although Paramount believes that the expectations reflected in
such forward-looking information are reasonable, undue reliance
should not be placed on them as Paramount can give no assurance
that such expectations will prove to be correct. Forward-looking
information is based on expectations, estimates and projections
that involve a number of risks and uncertainties which could cause
actual results to differ materially from those anticipated by
Paramount and described in the forward-looking information. The
material risks and uncertainties include, but are not limited
to:
- fluctuations in natural gas and liquids prices;
- changes in foreign currency exchange rates and interest
rates;
- the uncertainty of estimates and projections relating to future
revenue, production, reserve additions, liquids yields (including
condensate to natural gas ratios), resource recoveries, royalty
rates, taxes and costs and expenses;
- the ability to secure adequate product processing,
transportation, de-ethanization, fractionation, and storage
capacity on acceptable terms;
- operational risks in exploring for, developing and producing,
natural gas and liquids;
- the ability to obtain equipment, services, supplies and
personnel in a timely manner and at an acceptable cost;
- potential disruptions, delays or unexpected technical or other
difficulties in designing, developing, expanding or operating new,
expanded or existing facilities (including third-party
facilities);
- processing, pipeline, de-ethanization, and fractionation
infrastructure outages, disruptions and constraints;
- risks and uncertainties involving the geology of oil and gas
deposits;
- the uncertainty of reserves estimates;
- general business, economic and market conditions;
- the ability to generate sufficient cash flow from operations
and obtain financing to fund planned exploration, development and
operational activities and meet current and future commitments and
obligations (including product processing, transportation,
de-ethanization, fractionation and similar commitments and
obligations);
- changes in, or in the interpretation of, laws, regulations or
policies (including environmental laws);
- the ability to obtain required governmental or regulatory
approvals in a timely manner, and to obtain and maintain leases and
licenses;
- the effects of weather and other factors including wildlife and
environmental restrictions which affect field operations and
access;
- the timing and cost of future abandonment and reclamation
obligations and potential liabilities for environmental damage and
contamination;
- uncertainties regarding aboriginal claims and in maintaining
relationships with local populations and other stakeholders;
- the outcome of existing and potential lawsuits, regulatory
actions, audits and assessments; and
- other risks and uncertainties described elsewhere in this
document and in Paramount's other filings with Canadian securities
authorities.
The foregoing list of risks is not exhaustive. For more
information relating to risks, see the section titled "RISK
FACTORS" in Paramount's current annual information form. The
forward-looking information contained in this document is made as
of the date hereof and, except as required by applicable securities
law, Paramount undertakes no obligation to update publicly or
revise any forward-looking statements or information, whether as a
result of new information, future events or otherwise.
Non-GAAP Measures
In this document "Adjusted funds flow ", "Netback", "Net debt
(cash)" and "Exploration and development capital", collectively the
"Non-GAAP measures", are used and do not have any standardized
meanings as prescribed by International Financial Reporting
Standards.
Adjusted funds flow refers to cash from operating activities
before net changes in operating non-cash working capital,
geological and geophysical expenses, asset retirement obligation
settlements and transaction and reorganization costs. Adjusted
funds flow is commonly used in the oil and gas industry to assist
management and investors in measuring the Company's ability to fund
capital programs and meet financial obligations. Refer to the
Consolidated Results section of the Company's Management's
Discussion and Analysis for the three months ended March 31, 2018 for the calculation thereof.
Netback equals petroleum and natural gas sales less royalties,
operating costs and transportation and NGLs processing costs.
Netback is commonly used by management and investors to compare the
results of the Company's oil and gas operations between periods.
Refer to the Operating Results section of the Company's
Management's Discussion and Analysis for the three months ended
March 31, 2018 for the calculation
thereof. Net debt (cash) is a measure of the Company's overall debt
position after adjusting for certain working capital amounts and is
used by management to assess the Company's overall leverage
position. Refer to the Liquidity and Capital Resources section of
the Company's Management's Discussion and Analysis for the three
months ended March 31, 2018 for the
calculation of Net debt (cash). Exploration and development capital
consists of the Company's spending on wells, infrastructure
projects, other property, plant and equipment and exploration and
evaluation assets and excludes spending related to land and
property acquisitions and corporate assets. The Exploration and
development capital measure provides management and investors with
information regarding the Company's capital spending on wells and
infrastructure projects separate from land and property acquisition
activity and corporate expenditures. Refer to the Property, Plant
and Equipment and Exploration Expenditures section of the Company's
Management's Discussion and Analysis for the three months ended
March 31, 2018 for the calculations
thereof.
Non-GAAP measures should not be considered in isolation or
construed as alternatives to their most directly comparable measure
calculated in accordance with GAAP, or other measures of financial
performance calculated in accordance with GAAP. The Non-GAAP
measures are unlikely to be comparable to similar measures
presented by other issuers.
Oil and Gas Measures and Definitions
Abbreviations
Liquids
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Natural
Gas
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Bbl
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Barrels
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Mcf/d
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Thousands of cubic
feet
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Bbl/d
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Barrels per
day
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MMcf/d
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Millions of cubic
feet per day
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MBbl
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Thousands of
barrels
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Bcf
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Billions of cubic
feet
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NGLs
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Natural gas
liquids
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AECO
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AECO-C reference
price
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Condensate
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Pentane and heavier
hydrocarbons
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NYMEX
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New York Mercantile
Exchange
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Oil
Equivalent
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Boe
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Barrels of oil
equivalent
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MBoe
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Thousands of barrels
of oil equivalent
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Boe/d
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Barrels of oil
equivalent per day
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This document contains disclosures expressed as "Boe", "$/Boe",
"MBoe" and "Boe/d". Natural gas equivalency volumes have been
derived using the ratio of six thousand cubic feet of natural gas
to one barrel of oil. Equivalency measures may be misleading,
particularly if used in isolation. A conversion ratio of six
thousand cubic feet of natural gas to one barrel of oil is based on
an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the well
head. For the three months ended March 31,
2018, the value ratio between crude oil and natural gas was
approximately 40:1. This value ratio is significantly different
from the energy equivalency ratio of 6:1. Using a 6:1 ratio would
be misleading as an indication of value. The term "liquids" is used
to represent oil, condensate and Other NGLs. NGLs consist of
condensate and Other NGLs. The term "Other NGLs" includes ethane,
propane and butane.
SOURCE Paramount Resources Ltd.