CALGARY, Nov. 9, 2017 /CNW/ -
OIL AND GAS OPERATIONS
- Paramount completed two major transactions in the third quarter
of 2017, acquiring Apache Canada Ltd. (ʺApache Canadaʺ) in August
and completing a merger with Trilogy Energy Corp. (ʺTrilogyʺ) in
September.
- During October 2017, the first
full month of operations for the combined entities, Paramount's
estimated sales volumes averaged over 98,000 Boe/d (38 percent
Liquids).
- Average sales volumes for the fourth quarter are expected to
exceed 95,000 Boe/d, with greater than 38 percent Liquids
volumes.
- Paramount's third quarter 2017 sales volumes averaged 49,023
Boe/d (40 percent Liquids).
- In the Grande Prairie Region, the 2016/17 Karr-Gold Creek capital program is wrapping up
with the the final six wells of the 27-well Montney program scheduled to be completed and
brought on production before year-end 2017. Paramount expects
fourth quarter production from the Grande Prairie Region to exceed
35,000 Boe/d (approximately 50 percent Liquids).
- In the Kaybob Region, a total of seven wells were rig released
and twelve wells were completed in the third quarter of 2017,
including the completion and tie-in of a six (3.1 net) well pad at
Kaybob South Duvernay in September. The Company expects
fourth quarter production from the Kaybob Region to exceed 40,000
Boe/d (approximately 33 percent Liquids).
- The Central Alberta and Other
Region includes assets and production in the Northwest Territories, northeast British Columbia, northwest Alberta, and central Alberta. Drilling
and completion activity in the Region during the third quarter took
place at the Birch joint-venture in northeast British Columbia. Paramount expects fourth
quarter production from the Central and Other Region to be
approximately 20,000 Boe/d (30 percent Liquids).
- Capital expenditures in the third quarter of 2017 totaled
$122.0 million. The majority of the
capital spending was directed towards the Karr-Gold Creek Montney
development program in the Grande Prairie Region.
CORPORATE
- Paramount's revolving bank credit facility (the ʺFacilityʺ) was
increased from $300 million to
$700 million in November 2017. At Paramount's request, the size
of the Facility can be further increased by $300 million to $1.0
billion.
- Approximately $315 million was
drawn on the Facility as of November 6,
2017.
- Trilogy's $285 million bank
credit facility has been repaid and cancelled.
- Third quarter 2017 funds flow from operations totaled
$45.3 million compared to
$3.8 million in the third quarter of
2016.
- Transition efforts are in full swing with a management team
comprised of representation from all three companies. The Company
has reorganized into three operating regions while also creating
discipline-based leadership roles to facilitate project execution
and best practices and to ensure integration across the
organization.
- Since October 1, 2017, Paramount
has entered into hedges for 10,000 Bbl/d of Liquids for 2018 at an
average WTI price of C$69.84/Bbl. For
the remainder of 2017, the Company has 4,000 Bbl/d of Liquids
hedged at an average WTI price of C$70.80/Bbl and 2,000 Bbl/d hedged at a WTI price
of US$54.48/Bbl.
- The Company has secured firm service transportation capacity
for approximately 60,000 GJ/d of natural gas for delivery to the
Dawn natural gas hub in Ontario
for sale to eastern natural gas markets.
OIL AND GAS OPERATIONS
In the third quarter of 2017 sales volumes averaged 49,023
Boe/d, including 40 percent Liquids volumes. This includes 46 days
of production from the Apache Canada assets and 19 days of
production from the Trilogy assets. For the full month of
October, the Company's estimated monthly sales averaged over 98,000
Boe/d, including approximately 38 percent Liquids volumes. Average
sales volumes for the fourth quarter of 2017 are expected to exceed
95,000 Boe/d, with 38 percent Liquids volumes.
Capital expenditures for the Company in the third quarter of
2017 were $122.0 million. Paramount
estimates approximately $130 million
of capital will be spent in the fourth quarter, bringing total
projected annual spending for 2017 to approximately $510 million, excluding land and property
acquisitions.
Following the acquisition of Apache Canada (the ʺApache Canada
Acquisitionʺ) and the merger with Trilogy (the ʺTrilogy Mergerʺ),
Paramount has divided its oil and gas operating areas into three
operating regions: i) the Grande Prairie Region; ii) the Kaybob
Region and iii) the Central
Alberta and Other Region.
In the third quarter of 2017 the combined entities rig released
11 wells, completed 16 wells, and had 12 wells in the process of
being completed.
Grande Prairie Region
The focus within the Grande Prairie Region is the over-pressure
liquids-rich Deep Basin Montney trend. In the third quarter
Paramount added approximately 45,000 net acres to its land position
through the Apache Canada Acquisition and increased its total land
holding to approximately 147,000 net acres. In addition, the
Company has a material position of Deep Basin Cretaceous rights of
approximately 150,000 net effective acres targeting the
Dunvegan, Falher, Gething and Wilrich formations.
Production for the quarter averaged 24,000 Boe/d with
approximately 50 percent Liquids, despite a 20-day planned outage
at a third-party gas processing plant. Paramount expects fourth
quarter production from the Grande Prairie Region to continue to
exceed 35,000 Boe/d, comprised of approximately 50 percent
Liquids.
During the third quarter, a total of four wells were rig
released, four wells were completed and brought on production, and
12 wells were in the process of being completed and brought on
production.
The 2016/17 Karr Montney capital program is wrapping up with six
wells in-progress and scheduled to be on production before year-end
2017. This will complete the successful 27 (27.0 net) well program,
which delivered average sales volumes of around 26,600 Boe/d in
October 2017, including approximately
52 percent Liquids volumes. Peak wellhead throughput in the month
of October reached 30,500 Boe/d, with approximately 55 percent
Liquids volumes.
The table below summarizes the average peak 30-day initial
wellhead production rates for 21 of the 27 wells in the 2016/17
Karr Montney capital program:
|
|
|
|
|
|
Well
|
Pad
|
Peak 30
Day
Total
(1)
(Boe/d)
|
Peak 30
Day
Condensate
(1)
(Bbl/d)
|
%
Condensate
|
Days
on
Production
|
00/15-14-065-06W6/0
|
15-02
|
2,628
|
1,340
|
51
|
307
|
00/04-07-065-05W6/0
|
04-19
|
2,550
|
1,815
|
71
|
266
|
02/04-07-065-05W6/0
|
04-19
|
2,844
|
2,176
|
77
|
238
|
02/01-12-065-06W6/0
|
04-19
|
2,633
|
1,795
|
68
|
229
|
00/03-22-066-05W6/0
|
03-22
|
1,949
|
946
|
49
|
203
|
00/01-12-065-06W6/0
|
04-19
|
2,218
|
1,532
|
69
|
196
|
00/09-32-065-04W6/0
|
16-36
|
2,159
|
1,401
|
65
|
158
|
00/16-32-065/04W6/0
|
16-36
|
2,122
|
1,263
|
60
|
143
|
00/04-34-065-05W6/0
|
16-04
|
2,137
|
994
|
47
|
132
|
00/01-33-065-05W6/0
|
16-04
|
1,912
|
805
|
42
|
127
|
00/08-32-065-04W6/0
|
16-36
|
1,856
|
1,176
|
63
|
119
|
02/16-24-066-05W6/0
|
13-07
|
1,341
|
694
|
52
|
94
|
00/04-06-066-04W6/0
|
13-07
|
1,815
|
900
|
50
|
93
|
02/04-06-066-04W6/0
|
13-07
|
2,050
|
1,414
|
69
|
91
|
00/16-24-066-05W6/0
|
13-07
|
1,352
|
647
|
48
|
91
|
00/03-06-066-04W6/0
|
13-07
|
1,839
|
942
|
51
|
89
|
02/09-32-065-04W6/0
|
16-36
|
1,529
|
950
|
62
|
80
|
00/13-14-065-06W6/0
|
15-02
|
1,723
|
1,072
|
62
|
56
|
02/16-14-065-06W6/0
|
15-02
|
2,018
|
1,346
|
67
|
48
|
02/14-14-065-06W6/0
|
15-02
|
1,702
|
1,003
|
59
|
30
|
02/15-14-065-06W6/0
|
15-02
|
1,855
|
1,270
|
67
|
30
|
Average
|
|
2,011
|
1,212
|
59
|
134
|
(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. 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.
|
Drilling costs for the 21 wells averaged $3.7 million per well ($622 per meter of total depth or $1,281 per meter of lateral length) and
completion costs averaged $7.1
million per well ($103,000 per
stage or $1,032 per tonne of proppant
placed). Paramount increased the number of average fracs
pumped per day from about five on the 04-19 pad to an average of
more than 10 per day on the most recent pad, with as many as 17
frac stages pumped in a single 24-hour period.
The Karr 06-18 compression and dehydration facility (the ʺ06-18
Facilityʺ) produces to a nearby third party sour gas processing
plant where Paramount has firm natural gas transportation on TCPL
and downstream contracts for our condensate and NGLs volumes.
The 2016/17 delineation and land tenure program at the Wapiti
Montney property is nearly complete, with two wells rig released
and one well completed and tested in the third quarter of
2017. To date, the property has been delineated with nine
wells that have tested three landing zones in the Middle and Lower
Montney. A new third party sour gas processing plant, trunk lines,
and compression nodes are at various stages of engineering,
procurement and construction, with the first 150 MMcf/d of sour gas
processing capacity scheduled to be commissioned in the spring of
2019.
In the Resthaven/Jayar area, the 2016/17 program of five (4.5
net) Cretaceous wells and one (1.0 net) Montney well is near completion. In the
third quarter, one well was rig released, four wells were completed
and put on production, and one well is in the process of being
completed, tested and brought on production.
The Montney well at Resthaven
was drilled, completed and tied-in during the third quarter with
encouraging results. This Montney
well was completed with a similar design to those of the Karr
Montney program and had a completed length of approximately 2,700
meters with 70 x 100 tonne frac stages for proppant loading
intensity of about 2.6 tonnes per meter. The well continues
to flow on cleanup and has achieved an initial 30-day production
rate of approximately 1,314 Boe/d at the wellhead, about 33 percent
condensate. Wellhead production rates over the first 30 days have
increased day-over-day with the 30th day delivering approximately
1,780 Boe/d with 34 percent condensate. The Company plans to
closely monitor the well's longer-term performance and may
accelerate the development of the Montney in this area.
All of the new Resthaven/Jayar production is being processed
either in the 300 MMcf/d Pembina 08-11 deep cut gas plant where
Paramount holds a 16 percent interest (54 MMcf/d net capacity), or
the Resthaven 01-36 gas plant, where Paramount holds a 50 percent
interest (10 MMcf/d net capacity). Paramount has firm service
natural gas transportation on TCPL and downstream contracts for
condensate and NGLs to handle egress for production from the
Resthaven/Jayar area.
Kaybob Region
The focus in the Kaybob Region is Montney oil at Kaybob and Ante Creek,
Montney gas at Presley,
liquids-rich Duvernay at Kaybob
South and Smoky River and Gething oil. Paramount has added
about 900,000 net acres of land at Kaybob as a result of the Apache
Canada Acquisition and the Trilogy Merger, including approximately
88,000 net acres of tier one Montney oil acreage, 122,000 net acres of
liquids-rich Montney gas, and
136,000 net acres of Duvernay
rights, more than half of which are in the liquids-rich trends. In
addition to these Montney and
Duvernay land positions, Paramount
added additional acreage in stacked Cretaceous plays within the
Deep Basin at Kaybob.
Through the Apache Canada Acquisition and the Trilogy Merger,
Paramount also added strategically owned and operated facilities
including six natural gas processing plants and three oil
batteries. The natural gas processing capacity totals greater
than 150 MMcf/d and the oil batteries can process more than 40,000
Bbl/d of liquids.
During the third quarter, a total of seven wells were rig
released and 12 wells completed in the Kaybob Region, including a
six-well pad at Kaybob South Duvernay which tested completion
intensities up to 4.5 tonnes per meter. Production for the
Kaybob Region in the third quarter averaged approximately 13,500
Boe/d, approximately 31 percent Liquids volumes. Paramount expects
fourth quarter 2017 production from the Kaybob Region to exceed
40,000 Boe/d, with about 33 percent Liquids volumes.
The Company has implemented a new completion design in the
Kaybob Montney oil pool which on average has 45 percent more stages
and 290 percent higher proppant loading than the original
wells. The table below summarizes the average peak 30-day
initial wellhead rates for wells with the new completion
design.
|
|
|
|
|
Well
|
Peak 30
Day
Total
(1)
(Boe/d)
|
Peak 30
Day
Oil
(1)
(Bbl/d)
|
%
Oil
|
Days
on
Production
|
02/05-06-064-18W5/0
|
2,301
|
1,928
|
84
|
299
|
03/04-06-064-18W5/0
|
1,059
|
759
|
72
|
298
|
02/04-06-064-18W5/0
|
1,202
|
1,082
|
90
|
270
|
00/13-31-064-18W5/0
|
1,174
|
990
|
84
|
210
|
02/13-31-064-18W5/0
|
811
|
605
|
75
|
208
|
00/14-31-064-18W5/0
|
756
|
578
|
76
|
208
|
00/14-12-064-19W5/2
|
539
|
475
|
88
|
198
|
02/15-12-064-19W5/0
|
683
|
587
|
86
|
195
|
03/15-12-064-19W5/0
|
754
|
620
|
82
|
157
|
02/08-05-064-18W5/0
|
1,007
|
929
|
92
|
137
|
03/09-05-064-18W5/0
|
815
|
758
|
93
|
136
|
02/08-29-064-18W5/0
|
1,573
|
599
|
38
|
114
|
Average
|
1,056
|
826
|
80
|
203
|
(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
oil sales volumes are approximately 15 percent lower due to
shrinkage. 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.
|
Drilling costs for the 17 wells that were completed in the
Kaybob Region averaged $1.7 million
per well ($440 per meter of total
depth or $926 per meter of lateral
length), with completion costs averaging $0.9 million per well ($29,233 per stage or $1,500 per tonne of proppant placed). Paramount
will continue to operate a drilling rig through the fourth quarter
on this play.
The Kaybob Montney oil asset produces through owned and operated
sour natural gas processing and oil handling facilities that are
coupled with firm transportation for the solution gas and
downstream contracts for oil and NGLs volumes. The facilities
are dually connected to both the TCPL and Alliance systems for
natural gas volumes and the Pembina gathering system for crude
oil.
During the quarter, the Company brought on a new six-well pad on
its Kaybob South Duvernay lands and is excited by the
results. The wells on this pad had an average daily wellhead
production rate of approximately 1,600 Boe/d per well with about 51
percent condensate volumes over their first 30 days of
production. The production rates from this new pad are over a
brief period of time and not necessarily indicative of the
long-term performance. The average drill cost was
$4.6 million per well ($842 per meter of total depth or $2,030 per meter of lateral length) and the
average completion cost was $6.0
million per well ($147,000 per
stage or $711 per tonne of proppant
placed). The six-well pad tested two proppant loading
intensities at approximately 55-meter stage spacing and the Company
is currently evaluating the results to determine the optimal
proppant loading intensity.
The Kaybob South Duvernay asset produces through third party
facilities under firm agreements, again coupled with firm
transportation for natural gas and downstream contracts for
condensate and NGLs volumes.
Central Alberta and Other
Region
The Central Alberta and Other
Region includes assets and production in the Northwest Territories, northeast British Columbia, northwest Alberta, and central Alberta. There are
a number of material land and resource positions in the region
including Willesden Green and East Shale Basin Duvernay. The
following table summarizes the noteworthy positions in the
region:
|
|
Description
|
Approximate Net
Acres
|
Willesden Green
Duvernay
|
63,000
|
East Shale Basin
Duvernay
|
30,000
|
Fee Simple
Lands
|
176,000
|
Cardium
|
187,000
|
Glauconite
|
76,000
|
Ellerslie
|
95,000
|
During the third quarter, drilling and completion activity in
the Central Alberta and Other
Region took place at the non-operated Birch joint-venture lands in
northeast British Columbia.
Production for the region for the third quarter averaged about
11,000 Boe/d (28 percent Liquids). Paramount expects fourth
quarter 2017 production from the Central
Alberta and Other Region to be approximately 20,000 Boe/d
with approximately 30 percent Liquids.
2018 GUIDANCE AND OUTLOOK
Paramount's 2018 capital budget is focused on liquids-rich
growth opportunities while maintaining a strong balance sheet.
Paramount expects sales volumes to average approximately 100,000
Boe/d in 2018, including 40 percent Liquids volumes. The Company's
sales volumes are expected to remain at this level until production
at Wapiti begins to ramp up in the spring of 2019 when 150 MMcf/d
of new third-party gas processing capacity is scheduled to come
on-stream.
Capital expenditures for 2018 are expected to be approximately
$600 million including maintenance,
optimization and exploration expenses, excluding acquisitions or
divestitures. In addition, the Company intends to spend
approximately $28 million on
abandonment and suspension activities in 2018.
Approximately 50 percent of the $130
million of capital expenditures the Company expects to incur
in the fourth quarter of 2017 are related to the planned 2018
development program and include lease construction, drilling
operations and ordering of long-lead items.
The 2018 capital allocation is expected to be as follows: 68
percent liquids-rich Montney, 23
percent liquids-rich Duvernay, six
percent for maintenance/optimization projects and three percent for
other liquids-rich projects. Capital allocation by region is
forecast to be about 54 percent Grande
Prairie, 36 percent Kaybob and 10 percent Central/Other.
In 2018 the Company plans to drill between 70 and 75 net
development wells and complete up to 55 of those net wells.
The 55 net well completions will account for about 13 percent of
Paramount's proved plus probable booked undeveloped locations (as
at June 1, 2017). As the Company
furthers the development of its plays, additional locations will be
added to Paramount's reserves.
At an average drilling duration of 30 days and 270 operating
days per year per drilling rig, Paramount's wholly-owned Fox
Drilling fleet of seven rigs can accommodate approximately 1,900 of
the up to 2,500 drilling days that may be required for these
development wells. The remaining drilling days will be
contracted out based on cost of service, availability, reliability
and functionality of equipment.
In 2016/17 Paramount contracted pumping services for extended
periods of up to 12 months, and plans to employ the same strategy
in 2018 to ensure access to quality crews, equipment, and
materials. Paramount has a water management team and greater
than five million barrels of existing fresh water storage capacity
in Wapiti, Karr and Kaybob.
During the period from late-2016 through to the present,
Paramount has seen between 10 and 15 percent cost inflation in
drilling and completion activities. These increases have been
included in future development planning with any additional cost
inflation anticipated to be offset by savings due to multi-well pad
drilling, fresh water storage and economies of scale from the
combined businesses.
For budgeting and planning purposes, Paramount uses constant
prices and costs with US$50/Bbl WTI,
US$3.00/MMbtu NYMEX, US$1.00/MMbtu AECO basis, and a foreign exchange
rate of 1.25 Canadian dollars per US
dollar. Operating costs through the 2018 period are estimated to be
approximately $10.00 per Boe.
Transportation costs are expected to average $3.10 per Boe with royalties of approximately
$1.65 per Boe. Operating costs
per Boe and general and administrative costs are expected to
decline in the fourth quarter of 2018 as optimization and
synergistic benefits start to be realized.
Paramount expects to fund the portion of its 2018 budgeted
capital expenditures that are in excess of cash flow through
non-core asset divestitures and by drawings on the Company's
expanded bank credit facility.
Paramount has a portfolio of very profitable projects and
intends to invest in these while maintaining financial strength and
flexibility. This will provide the Company with the flexibility to
accelerate capital investments should macro conditions continue to
improve.
2018 Capital Program By Property
Wapiti Montney
In 2018 the Company will allocate about 25 percent of the
capital program to the Wapiti Montney asset in the form of
drilling, completions, water management, land tenure, and
geological studies. A 24-well drilling campaign (100 percent
working interest) will be kicked off with most of the well
completions to follow in early 2019 to align with the commissioning
and startup of the first phase of the third-party Wapiti gas
plant.
The Wapiti gas plant, trunk line connecting the east and west
blocks and compression nodes are in various stages of engineering,
procurement and construction with an anticipated onstream date in
the spring of 2019 as per the third party schedule. This
third-party infrastructure is complimented by a Leduc water disposal scheme which Paramount
will commence drilling the first of a series of water disposal
wells in 2018.
Paramount has firm natural gas transportation on TCPL which
ramps up from 50 MMcf/d in 2019 to 130 MMcf/d in early 2021 with
the potential to accelerate these volumes should Paramount choose
to do so.
Karr Montney
The Karr Montney asset is expected to be allocated approximately
27 percent of the 2018 capital program in the form of drilling,
completions, optimizations and facility expansions. Paramount
plans to expand the existing 06-18 Facility from its current 80
MMcf/d throughput capacity to about 100 MMcf/d of capacity in the
latter half of 2018. The 2018 program will see about 15 wells
drilled (five to be spud in the fourth quarter of 2017) and up to
10 wells completed. Paramount has a 100 percent working
interest in the wells in the 2018 program.
In addition to expanding the existing 06-18 Facility from 80 to
100 MMcf/d, the Company has kicked off front-end engineering design
and site clearing on a 50 MMcf/d expansion, which will see Karr
achieve throughput capacity of 150 MMcf/d in 2020. This new
owned and operated facility is being designed to allow for a
further 50 MMcf/d expansion, which would bring total owned and
contracted natural gas processing at Karr to 200 MMcf/d. Firm
transportation with TCPL is in place to achieve the goal of 150
MMcf/d of throughput capacity by the third quarter of 2020.
Kaybob Montney Oil
Approximately 13 percent of the 2018 capital program has been
assigned to the Kaybob Montney oil asset. This will consist
of drilling, completions, optimizations and infield infrastructure
projects to handle growth in oil production from the current 6,000
Bbl/d to approximately 8,000 Bbl/d. The 2018 program will see
about 22 new wells (100 percent working interest) drilled and
completed, plus an additional five completions from late-2017
drills.
The solution gas from the asset is produced into Paramount's
operated Kaybob North 08-09 gas plant (the ʺ08-09 Plantʺ) where
firm natural gas transportation is secured with TCPL. The gas
plant is dually connected to both TCPL and Alliance, providing for
future optionality.
Oil emulsion is treated at Paramount's owned and operated 12-10
oil battery with capacity of 20,000 Bbl/d, which is pipeline
connected to Pembina. The Company has downstream contracts in place
to match throughput at the battery.
Paramount's development strategy at the Kaybob Montney Oil asset
is to maintain oil production flat at about 8,000 Bbl/d, with
optionality to increase throughput in the event of higher oil
prices.
Kaybob Smoky Duvernay
The 2018 capital program for the Kaybob Smoky Duvernay will see
a new four well pad (100 percent working interest, average 2,600
meter lateral length with proppant loading intensities up to 4.5
tonnes per meter) spudded in late-2017 (part of the fourth quarter
2017 capital spend estimate) and come on-stream in middle of
2018.
The new four well pad will produce to Paramount's owned and
operated Smoky 06-16 gas plant, which will have approximately 12
MMcf/d of throughput capacity after some minor capital investments.
The Smoky 06-16 plant is TCPL connected with firm transportation to
accommodate natural gas production. Condensate and NGLs will
be trucked to the 08-09 Plant and the 12-10 oil battery, which is
located about 15 miles east.
The 2018 capital program is Phase 1 of the development of the
Kaybob Smoky Duvernay asset. Phase 2 will consist of further
modifications to the Smoky 06-16 gas plant to increase throughput
capacity to about 20 MMcf/d in 2019. Phase 3 of the
development will include a pipeline connection to the Kaybob North
08-09 gas plant and some modifications/enhancements to the Kaybob
North 08-09 gas plant for handling Duvernay liquids. Phase 3 will add
incremental throughput capacity of approximately 40 MMcf/d,
bringing the total throughput capacity for the asset up to 60
MMcf/d for middle of 2020.
The growth plan at the Kaybob Smoky Duvernay asset is supported
by firm natural gas transportation on TCPL and downstream contracts
for the condensate and NGLs.
Kaybob South Duvernay
In 2018 the Company will allocate up to $50 million to the Kaybob South Duvernay
asset. Paramount's average working interest in the asset is
about 60 percent and the 2018 program average working interest is
51 percent. The program will consist of drilling up to 11
gross wells and completing five of those wells in 2018 with the
remainder being completed in early-2019.
The asset produces through third party facilities under firm
contracts with current throughput capacity limited to 40 MMcf/d at
the 15-28 compression and dehydration facility. The 15-28
facility is expandable and the Company has firm service natural gas
processing capacity in excess of 80 MMcf/d at a downstream
third-party natural gas processing plant.
Paramount has firm natural gas transportation on TCPL that
aligns with the current third-party facilities solution and would
be addressed in an expansion scenario.
Other Exploration and Development Capital
The 2018 capital program includes about $60 million for other high-graded development
projects including Birch Montney, Willesden Green Duvernay, Hoadley
Glauconite, Gething oil and Ante Creek Montney. In total, the
Company plans to drill around 11 gross wells (7.8 net wells) and
complete 10 gross wells (6.8 net wells). All but one of the
completed wells will produce through owned and operated
infrastructure which is accompanied by firm transportation
contracts for natural gas. The exception is Birch Montney,
where Paramount has ownership in facilities that are operated by a
joint-venture partner.
The 2018 capital plan excludes non-operated opportunities which
may arise throughout the year, which will be evaluated on a
case-by-case basis to determine the economic feasibility, risk
profile, and strategic rationale.
Optimization Capital
In 2018 the Company has allocated approximately $45 million to maintenance and optimization
projects to add production, reduce base decline, and achieve
operating cost savings. The focus of these optimization
projects is in the Kaybob area, where there are a number of
opportunities to re-route production from third party facilities to
owned and operated facilities. These investment opportunities
are possible due to the overlap of the Trilogy and Apache Canada
land and infrastructure positions in Kaybob, which provide
significant opportunities for cost saving synergies.
TECHNOLOGY UPDATE
Over the course of three years Paramount has evolved completion
designs from open-hole packer systems with oil-based fluid to cased
hole designs with slickwater fluid and pump rates more than 14
m3/min. Stage spacing has decreased from up to 100m down to
as low as 40m with proppant loading intensities increasing from 0.6
t/m to as high as 4.5 t/m.
Paramount continues to investigate and research the evolution of
well design and will test concepts around plug optimization, zipper
fracturing techniques, casing string design, and artificial lift
technologies in 2018.
In 2018 a key focus for Paramount is data acquisition projects
including micro-seismic, production logging with fiber, pilot wells
and coring, landing zone optimization, well density tests, stacked
development tests and water reuse applications.
Paramount strives to be a leader in well completion designs and
optimizing well performance with a specific focus on condensate
recoveries. The Company has embraced data analytics and is
monitoring competitors in its own basin and plays as well as
operators south of the border. Paramount is focused on the
optimal asset allocation and maximizing oil and condensate recovery
from our liquids-rich resource plays.
SUBSEQUENT EVENTS
Since October 1, 2017, Paramount
has entered into hedges for 10,000 Bbl/d of Liquids for 2018 at an
average WTI price of C$69.84/Bbl. For
the remainder of 2017, the Company has 4,000 Bbl/d of Liquids
hedged at an average WTI price of C$70.80/Bbl and 2,000 Bbl/d hedged at a WTI price
of US$54.48/Bbl.
The Company will receive US$1.1
million of locked-in gains on natural gas hedging contracts
in the fourth quarter of 2017 and has an additional 20,000 MMBtu/d
hedged at a NYMEX price of US$3.40/MMbtu until the end of the year.
The Company has secured firm service transportation capacity for
approximately 60,000 GJ/d of natural gas for delivery to the Dawn
natural gas hub in Ontario for
sale to eastern natural gas markets.
|
OPERATING AND
FINANCIAL RESULTS (1)
($ millions, except
as noted)
|
|
Three months
ended
September
30
|
Nine months
ended
September
30
|
|
2017
|
2016
|
%
Change
|
2017
|
2016
|
%
Change
|
Sales Volumes
(Boe/d)
|
|
|
|
|
|
|
|
PRL
(2)
|
25,294
|
11,148
|
127
|
19,975
|
11,583
|
72
|
|
Apache
Canada
|
18,960
|
-
|
100
|
6,389
|
-
|
100
|
|
Trilogy
|
4,769
|
-
|
100
|
1,607
|
-
|
100
|
Ongoing
Operations
|
49,023
|
11,148
|
340
|
27,971
|
11,583
|
141
|
|
Musreau Assets
(2)
|
-
|
13,638
|
(100)
|
-
|
26,979
|
(100)
|
Total
|
49,023
|
24,786
|
98
|
27,971
|
38,562
|
(27)
|
Netback
|
|
|
|
|
|
|
|
Natural gas
revenue
|
30.9
|
21.6
|
43
|
62.9
|
68.6
|
(8)
|
|
Condensate and oil
revenue
|
74.2
|
25.1
|
196
|
152.2
|
121.7
|
25
|
|
Other NGLs revenue
(3)
|
9.8
|
4.8
|
104
|
15.2
|
25.3
|
(40)
|
|
Royalty and sulphur
revenue
|
1.6
|
0.2
|
700
|
2.3
|
0.9
|
156
|
Petroleum and
natural gas sales
|
116.5
|
51.7
|
125
|
232.6
|
216.5
|
7
|
|
Royalties
|
(5.0)
|
(0.1)
|
NM
|
(7.8)
|
(2.1)
|
271
|
|
Operating
expense
|
(47.8)
|
(25.0)
|
91
|
(79.8)
|
(86.1)
|
(7)
|
|
Transportation and
NGLs processing (4)
|
(12.3)
|
(12.7)
|
(3)
|
(26.6)
|
(52.2)
|
(49)
|
Netback
|
51.4
|
13.9
|
270
|
118.4
|
76.1
|
56
|
|
($/Boe)
|
11.40
|
6.12
|
86
|
15.49
|
7.20
|
115
|
|
|
|
|
|
|
|
Exploration and
Capital Expenditures
|
|
|
|
|
|
|
|
Wells and
exploration
|
100.6
|
46.5
|
116
|
330.1
|
83.1
|
297
|
|
Facilities and
gathering
|
21.4
|
0.1
|
NM
|
50.8
|
9.8
|
418
|
Principal
Properties Capital (5)
|
122.0
|
46.6
|
162
|
380.9
|
92.9
|
310
|
|
|
|
|
|
|
|
Net
income
|
223.5
|
1,029.4
|
(78)
|
289.5
|
952.9
|
(70)
|
|
per share –
diluted ($/share)
|
1.97
|
9.64
|
(80)
|
2.65
|
8.97
|
(70)
|
Funds flow from
operations
|
45.3
|
3.8
|
NM
|
108.6
|
21.3
|
410
|
|
per share –
diluted ($/share)
|
0.40
|
0.04
|
NM
|
0.99
|
0.20
|
395
|
Total
assets
|
|
|
|
5,020.9
|
2,130.3
|
136
|
Net debt
(cash)
|
|
|
|
564.3
|
(385.3)
|
(246)
|
Investments in
other entities – market value (6)
|
|
|
|
56.5
|
466.7
|
(88)
|
Common shares
outstanding (thousands)
|
|
|
|
134.8
|
106.3
|
27
|
(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)
|
In 2016, the Company
sold its natural gas processing facilities and the majority of its
oil and gas properties in the Musreau/Kakwa area of west central
Alberta (the ʺMusreau Assetsʺ). Disclosures of results for the
three and nine months ended September 30, 2016 for "Ongoing
Operations" exclude amounts attributable to these sold facilities
and oil and gas properties. "PRL" means Paramount's existing
operations prior to the Apache Canada Acquisition and the Trilogy
Merger excluding the Musreau Assets.
|
(3)
|
Other NGLs means
ethane, propane and butane.
|
(4)
|
Includes downstream
natural gas, NGLs and oil transportation costs and NGLs
fractionation costs incurred by the Company.
|
(5)
|
Principal Properties
Capital includes capital expenditures and geological and
geophysical costs related to the Company's Principal Properties and
excludes land acquisitions.
|
(6)
|
Based on the
period-end closing prices of publicly-traded investments and the
book value of the remaining investments.
|
(7)
|
NM Not
meaningful
|
Paramount is an independent, publicly traded, Canadian energy
company that explores and develops conventional and unconventional
petroleum and natural gas prospects, including long-term
unconventional exploration and pre-development projects, and holds
a portfolio of investments in other entities. The Company's
principal properties are primarily 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 third quarter 2017 results, including Management's
Discussion and Analysis and the Company's Consolidated Financial
Statements can be obtained at:
http://files.newswire.ca/1509/PRL_Q3_Results.pdf
This information will also be made available shortly through
Paramount's website at www.paramountres.com and 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 and sales volumes (including the Liquids
component thereof);
- forecast capital expenditures (including the plays, regions and
activities where, or in respect of which, this capital is expected
to be spent), royalties, operating costs, abandonment and
suspension costs, and transportation costs;
- exploration, development, and associated operational plans and
strategies (including planned drilling and completion programs,
well tie-ins, and facility expansions, and the anticipated timing
thereof) and the Company's anticipated sources of funds to carry
out such plans and strategies (including planned non-core asset
divestitures);
- plans for securing the necessary drilling, completion and other
services required to carry out the Company's 2018 development
program;
- anticipated levels of cost inflation for drilling and
completion services and the Company's anticipated ability to offset
any additional cost increases by various means including increased
economies of scale;
- the percentage of Paramount's currently booked proved and
probable and high-graded Montney
and Duvernay locations that its
expects to drill in 2018;
- the Company's continued financial flexibility to accelerate its
capital programs if industry conditions warrant; 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, future 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 and resources 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 enter into and maintain leases
and licenses;
- the effects of weather;
- 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 "Funds flow from operations", "Netback", ʺNet
Debt (Cash)ʺ, ʺAdjusted Working Capitalʺ, "Exploration and Capital
Expenditures", "Principal Properties Capital" and "Investments in
other entities – market value", collectively the "Non-GAAP
measures", are used and do not have any standardized meanings as
prescribed by International Financial Reporting Standards.
Funds flow from operations refers to cash from (used in)
operating activities before net changes in operating non-cash
working capital, geological and geophysical expenses, asset
retirement obligation settlements and corporate acquisition and
merger costs. Funds flow from operations 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
and nine months ended September 30,
2017 for the calculation of funds flow from operations.
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 Principal Properties section of the Company's
Management's Discussion and Analysis for the three and nine months
ended September 30, 2017 for the
calculation of netback. Net debt (cash) is a measure of the
Company's overall debt position after adjusting for certain working
capital and other 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 calculation of Net debt (cash) and Adjusted
working capital. Exploration and capital expenditures
consist of the Company's spending on wells and infrastructure
projects, other property, plant and equipment, land and property
acquisitions and geological and geophysical costs incurred. The
closest GAAP measure to exploration and development expenditures is
property, plant and equipment and exploration cash flows under
investing activities in the Company's Consolidated Statement of
Cash Flows, which includes all of the items included in exploration
and capital expenditures, except for geological and geophysical
costs, which are expensed as incurred. Principal properties
capital includes capital expenditures and geological and
geophysical costs related to the Company's Principal Properties
business segment, and excludes land acquisitions. The principal
properties capital measure provides management and investors with
information regarding the Company's Principal Properties spending
on wells and infrastructure projects separate from land acquisition
activity and capitalized interest. Refer to the Advisories section
of the Company's Management's Discussion and Analysis for the three
and nine months ended September 30,
2017 for the calculation of exploration and capital
expenditures and principal properties capital. Investments in
other entities – market value reflects the Company's
investments in enterprises whose securities trade on a public stock
exchange at their period end closing price (e.g. Trilogy Energy
Corp. (2016), MEG Energy Corp., Blackbird Energy Inc., Marquee
Energy Ltd., RMP Energy Inc., Strategic Oil & Gas Ltd. and
others) and investments in all other entities at book value.
Paramount provides this information because the market values of
equity-accounted investments, which are significant assets of the
Company, are often materially different than their carrying values.
Refer to the Strategic Investments section of the Company's
Management's Discussion and Analysis for the three and nine months
ended September 30, 2017 for
information on carrying and market values.
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
The term "Liquids" means oil, condensate and Other NGLs (ethane,
propane and butane).
Abbreviations
Liquids
|
|
Natural
Gas
|
Bbl
|
Barrels
|
|
Mcf
|
Thousands of cubic
feet
|
Bbl/d
|
Barrels per
day
|
|
MMcf
|
Millions of cubic
feet
|
MBbl
|
Thousands of
barrels
|
|
MMcf/d
|
Millions of cubic
feet per day
|
NGLs
|
Natural gas
liquids
|
|
MMbtu
|
Millions of British
thermal units
|
Condensate
|
Pentane and heavier
hydrocarbons
|
|
|
|
|
|
|
|
Oil
Equivalent
|
|
|
|
Boe
|
Barrels of oil
equivalent
|
|
|
|
Boe/d
|
Barrels of oil
equivalent per day
|
|
|
|
|
|
|
|
|
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 nine
months ended September 30, 2017, the
value ratio between crude oil and natural gas was approximately
23:1. 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.
SOURCE Paramount Resources Ltd.