CALGARY, March 13, 2018 /CNW/ - Cequence Energy Ltd.
("Cequence" or the "Company") (TSX: CQE) is pleased to announce its
year-end reserve evaluation as prepared by its qualified
independent reserve evaluator as well as its operating and
financial results for the fourth quarter and year ended
December 31, 2017. The Company's
Consolidated Financial Statements and Management's Discussion and
Analysis are available at www.cequence-energy.com and on SEDAR at
www.sedar.com.
2017 Highlights
- Achieved full year 2017 production of 8,139 boe/d and increased
liquids weighting to 17 percent;
- Increased funds flow from operations from 2016 by 72% to
$19.3 million or $0.08/share;
- Improved egress with firm service contracted for all of the
Company's Simonette natural gas production;
- Added market diversity away from AECO with 10,850 GJ/d of
production to be sold at Dawn beginning April 1, 2018; and
- Drilled, completed, and tied in 3 gross (2 net) Dunvegan oil wells this winter with production
to commence the middle of March, 2018.
Comparative financial and operating information for 2017 and
2016 are as follows:
|
|
Three months
ended December
31,
|
Twelve months
ended December
31,
|
(000's except per
share and per unit amounts)
|
|
|
|
|
|
|
|
|
|
2017
|
2016
|
%
Change
|
2017
|
2016
|
%
Change
|
FINANCIAL
|
|
|
|
|
|
|
|
Total
revenue(1)
|
|
13,585
|
17,253
|
(21)
|
65,836
|
59,074
|
11
|
Comprehensive
loss
|
|
(6,638)
|
(9,077)
|
(27)
|
(99,362)
|
(28,057)
|
(254)
|
Per share – basic and
diluted
|
|
(0.03)
|
(0.04)
|
(25)
|
(0.40)
|
(0.13)
|
(208)
|
Funds flow from
operations (2)(5)
|
|
1,583
|
6,625
|
(76)
|
19,329
|
11,250
|
72
|
Per share, basic and
diluted
|
|
0.01
|
0.03
|
(67)
|
0.08
|
0.05
|
60
|
Capital expenditures,
before acquisitions (dispositions)
|
|
5,593
|
11,460
|
(51)
|
25,857
|
22,590
|
14
|
Capital expenditures,
including acquisitions (dispositions)
|
|
1,316
|
11,406
|
(88)
|
21,580
|
17,296
|
25
|
Net debt
(3)
|
|
(68,501)
|
(64,031)
|
7
|
(68,501)
|
(64,031)
|
7
|
Weighted average
shares outstanding – basic & diluted
|
|
245,528
|
235,028
|
4
|
245,528
|
217,061
|
13
|
OPERATING
|
|
|
|
|
|
|
|
Production
volumes
|
|
|
|
|
|
|
|
Natural gas
(Mcf/d)
|
|
33,331
|
45,005
|
(26)
|
40,466
|
45,442
|
(11)
|
Crude oil
(bbls/d)
|
|
283
|
140
|
102
|
344
|
177
|
94
|
Natural gas liquids
(bbls/d)
|
|
257
|
209
|
23
|
254
|
237
|
7
|
Condensate
(bbls/d)
|
|
617
|
760
|
(19)
|
797
|
841
|
(5)
|
Total
(boe/d)
|
|
6,713
|
8,609
|
(22)
|
8,139
|
8,826
|
(8)
|
Sales
prices
|
|
|
|
|
|
|
|
Natural gas,
including realized hedges ($/Mcf)
|
|
2.33
|
2.92
|
(20)
|
2.53
|
2.27
|
11
|
Crude oil and
condensate, including realized hedges ($/bbl)
|
|
66.73
|
56.27
|
19
|
61.44
|
52.17
|
18
|
Natural gas liquids
($/bbl)
|
|
38.55
|
25.61
|
51
|
30.72
|
21.94
|
40
|
Total
($/boe)
|
|
22.00
|
21.78
|
1
|
22.16
|
18.29
|
21
|
Netback
($/boe)
|
|
|
|
|
|
|
|
Price, including
realized hedges
|
|
22.00
|
21.78
|
1
|
22.16
|
18.29
|
21
|
Royalties
|
|
(0.63)
|
(0.59)
|
7
|
(1.06)
|
(0.48)
|
121
|
Transportation
|
|
(1.66)
|
(1.45)
|
14
|
(1.88)
|
(1.24)
|
52
|
Operating
costs
|
|
(12.91)
|
(7.81)
|
65
|
(9.29)
|
(8.49)
|
9
|
Operating
netback
|
|
6.80
|
11.93
|
(43)
|
9.93
|
8.08
|
23
|
General and
administrative(5)
|
|
(1.88)
|
(1.81)
|
4
|
(1.48)
|
(2.77)
|
(47)
|
Interest(4)
|
|
(2.46)
|
(1.92)
|
28
|
(2.07)
|
(1.93)
|
7
|
Cash
netback
|
|
2.46
|
8.20
|
(70)
|
6.38
|
3.38
|
89
|
Notes:
|
(1)
|
Total revenue is
presented gross of royalties and includes realized gains (loss) on
commodity contracts.
|
(2)
|
Funds flow from
operations is calculated as cash flow from operating activities
before adjustments for decommissioning liabilities expenditures and
net changes in non-cash working capital.
|
(3)
|
Net debt is
calculated as working capital (deficiency) less the principal value
of senior notes.
|
(4)
|
Represents finance
costs less amortization on transaction costs and accretion expense
on senior notes and provisions.
|
(5)
|
For the three and
twelve months ended December 31, 2016, general and administrative
expenses and funds flow from operations includes $nil and $2,341 in
restructuring charges (2017 - $nil).
|
Financial
Natural gas prices remained low in both 2016 and 2017 with AECO
prices averaging $2.18/mcf and
$2.23/mcf, respectively.
Conversely, crude oil and NGL prices increased year over year
contributing to an increase in annual funds flow from operations of
72 percent to $19.3 million. Fourth
quarter funds flow of $1.6 million
was negatively impacted by low AECO natural gas prices in October
and higher operating costs related to a field water management
project which was completed in the fourth quarter. For the
twelve months ended December 31,
2017, the Company recorded a comprehensive loss of
$99.4 million as the Company recorded
impairments of $96.2 million in the
second quarter of 2017 as a result of a lower outlook for crude oil
and natural gas prices.
Capital expenditures for the year were $25.9 million ($21.6 net of dispositions) and focused on wells
with higher oil and liquids content. Total capital was allocated as
follows: $14.2 million (55%) weighted
toward Q1 2017 completion and equipping of Montney wells, $7.2
million (28%) toward Dunvegan oil drilling, completion, equipping,
and oil facility tie-in, and $2.4
million (9%) for operating initiatives including water
disposal well completion, equipment, and related disposal facility
spending. With the outlook for natural gas prices remaining
weak in 2018, the Company does not expect to drill any additional
wells in the first half of 2018.
Financial leverage has improved over the past year as the
Company managed total debt levels by reducing capital
expenditures. December 31, 2017
net debt is $68.5 million
(December 31, 2016 - $64.0 million) or 3.5 times trailing annual funds
flow (December 31, 2016 - 5.7
times). The senior credit facility of $12 million remain undrawn other than letters of
credit of $1.5 million.
Reflecting the challenging commodity pricing environment and its
effects on the Company's cash flows and liquidity and the Company's
current debt, among other factors, the Company's financial
statements continue to disclose there is significant doubt in the
Company's ability to continue as a going concern. Further
details are set forth in the annual financial statements available
on Sedar.
The Company has hedged approximately 13% of its 2018 estimated
production and has diversified its natural gas sales with a
contract to sell 10,850 GJ/d in the Dawn, Ontario market. In the fourth quarter
the Company's NGTL firm service was increased to 35,000 mmcf/d at
Simonette which is expected to improve netbacks by reducing the
Company's reliance on more expensive short-term
transportation.
2017 Operational and Production
During the winter season of 2017/2018, Cequence has drilled and
completed 3 gross (2 net) Dunvegan
oil wells as follow up to the successful 2 gross (1 net) in
2016/2017. The new wells are scheduled to be producing in
mid-March, 2018.
For the year ended December 31,
2017, operating costs averaged $9.29 per boe in 2017, up 9% from 2016, with
operating costs up 65% in the fourth quarter to $12.91/boe. In the second half of 2017 the
Company had one time expenses associated with accelerating a water
handling and disposal project to reduce its surface water at the
Simonette field. Total costs of the project were $1.3 million ($2.15/boe) for the fourth quarter and
$3.3 million year to date
($1.36/boe). The onetime costs
were associated with storing water at surface, transferring water
to a water disposal well and dismantling surface tanks.
During the water disposal project, 2/3rds of the Simonette field
was shut-in for a week to utilize the pipeline system for water
transfer. This pipeline use was conducted during a period of low
gas prices. The water project was completed in December and is
expected to significantly reduce ongoing water handling costs
beginning in January 2018. Total
operating costs for 2018 are expected to be approximately
$9.50 - $10.50 per boe.
Corporate production for the three and twelve months ended
December 31, 2017 averaged 6,713
boe/d and 8,139 boe/d, respectively, compared to production of
8,609 boe/d and 8,826 boe/d in 2016. Oil and liquids
production for the same periods increased to 1,157 bbl/d and 1,359
bbl/d up 4% and 8% respectively.
2017 Independent Reserve Evaluation Matters
GLJ Petroleum Consultants ("GLJ") prepared the reserves report
effective December 31, 2017
(collectively referred to herein as the "GLJ Report") for the oil,
natural gas liquids and natural gas reserves attributable to the
properties of Cequence. The GLJ Report was prepared in accordance
with the definitions, standards and procedures contained in the
Canadian Oil and Gas Evaluation Handbook and National Instrument
51-101 ("NI 51-101"). Reserves highlights of the Company
include:
- Corporate reserves were 14.1 MMboe proved developed producing,
61.9 MMboe proven, and 124.2 MMboe on a proved plus probable
basis.
- Before production, Dunvegan
oil total proved and proved plus probable reserves increased by
129% and 43% respectively to 1.9 MMboe and 3.0 MMboe.
- Dunvegan oil total proven and
proven plus probable net present values at 10% discount rate are
$23.8 million and $34.0 million respectively using GLJ January 1, 2018 prices
- Booked Dunvegan oil inventory
is 3.5 net proven and 5.5 net proved plus probable
locations.
- Decreased Montney proved
reserves by 12% to 49.6 MMboe and proved plus probable reserves by
11% to 100.6 MMboe. 15 net proven Montney locations representing 8.5 MMboe were
adjusted to a later drilling date moving them into a probable
category. A separate 14 net proved plus probable Montney locations representing 10.3 MMboe were
removed for current economic factors.
- Recognized 4 additional proved plus probable locations
offsetting the Q1 2017 Montney development program.
The tables below are a summary of the oil, NGL and natural gas
reserves attributable to the properties of Cequence and the net
present value of future net revenue attributable to such reserves
as evaluated in the GLJ Report based on forecast price and cost
assumptions. The calculated NPVs include a deduction for estimated
future well abandonment and reclamation costs. It should not
be assumed that the estimates of future net revenues presented in
the tables below represent the fair market value of the reserves.
There is no assurance that the forecast prices and cost assumptions
will be attained and variances could be material. The recovery and
reserves estimates of Cequence's crude oil, natural gas liquids and
natural gas reserves provided herein are estimates only and there
is no guarantee that the estimated reserves will be recovered.
Actual crude oil, natural gas and natural gas liquids reserves may
be greater than or less than the estimates provided herein.
Summary of Oil, Natural Gas and NGL Reserves
|
Light and
Medium Crude
Oil
|
|
Tight Oil
|
|
Conventional
Natural Gas
|
|
Shale Gas
|
|
NGL
|
|
Total Oil
Equivalent
|
Reserves
Category
|
Gross(2)
|
|
Net(3)
|
|
Gross(2)
|
|
Net(3)
|
|
Gross(2)
|
|
Net(3)
|
|
Gross(2)
|
|
Net(3)
|
|
Gross(2)
|
|
Net(3)
|
|
Gross(2)
|
|
Net(3)
|
(Mbbl)
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcf)
|
|
MMcf
|
|
MMcf
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(MBOE)
|
|
(MBOE)
|
Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
Producing
|
255
|
|
211
|
|
0
|
|
0
|
|
31,416
|
|
28,818
|
|
41,358
|
|
35,574
|
|
1,734
|
|
1,190
|
|
14,118
|
|
12,133
|
|
Developed Non-
Producing
|
19
|
|
16
|
|
0
|
|
0
|
|
4,017
|
|
3,563
|
|
4,149
|
|
3,444
|
|
160
|
|
100
|
|
1,540
|
|
1,285
|
|
Undeveloped
|
645
|
|
544
|
|
0
|
|
0
|
|
27,587
|
|
25,852
|
|
206,937
|
|
178,806
|
|
6,513
|
|
5,430
|
|
46,245
|
|
40,083
|
Total
Proved
|
919
|
|
771
|
|
0
|
|
0
|
|
63,021
|
|
58,233
|
|
252,444
|
|
217,824
|
|
8,407
|
|
6,720
|
|
61,903
|
|
53,501
|
Probable
|
567
|
|
467
|
|
0
|
|
0
|
|
58,670
|
|
53,559
|
|
261,162
|
|
216,680
|
|
8,425
|
|
6,392
|
|
62,297
|
|
51,899
|
Total Proved
plus Probable
|
1,486
|
|
1,238
|
|
0
|
|
0
|
|
121,690
|
|
111,793
|
|
513,605
|
|
434,504
|
|
16,832
|
|
13,112
|
|
124,200
|
|
105,400
|
|
|
Notes:
|
(1)
|
Columns may not add
due to rounding.
|
(2)
|
"Gross" reserves
means the Company's working interest (operated and non‐operated)
share before deduction of royalties payable to others and without
including any royalty interests of the Company.
|
(3)
|
"Net" reserves means
the Company's working interest (operated and non‐operated) share
after deduction of royalty obligations plus the Company's royalty
interests in reserves.
|
Summary of Net Present Value of Future Net Revenue
|
Before Future Income
Tax Expenses Discounted at (%/year)
|
|
|
0
|
|
5
|
|
10
|
|
15
|
|
20
|
|
10
|
Reserves
Category
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
($/mcfe)
|
Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
Producing
|
|
121,056
|
|
101,934
|
|
87,683
|
|
77,010
|
|
68,832
|
|
1.20
|
|
Developed
Non-Producing
|
|
18,534
|
|
13,814
|
|
10,712
|
|
8,577
|
|
7,043
|
|
1.39
|
|
Undeveloped
|
|
447,989
|
|
240,361
|
|
133,412
|
|
74,259
|
|
39,592
|
|
0.55
|
Total
Proved
|
|
587,580
|
|
356,108
|
|
231,807
|
|
159,846
|
|
115,467
|
|
0.72
|
Probable
|
|
943,817
|
|
421,811
|
|
219,784
|
|
126,233
|
|
77,182
|
|
0.71
|
Total Proved plus
Probable
|
|
1,531,396
|
|
777,919
|
|
451,591
|
|
286,080
|
|
192,649
|
|
0.71
|
|
After Future Income
Tax Expenses Discounted at (%/year)
|
|
|
0
|
|
5
|
|
10
|
|
15
|
|
20
|
Reserves
Category
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
Proved
|
|
|
|
|
|
|
|
|
|
|
|
Developed
Producing
|
|
121,056
|
|
101,934
|
|
87,683
|
|
77,010
|
|
68,832
|
|
Developed
Non-Producing
|
|
18,534
|
|
13,814
|
|
10,712
|
|
8,577
|
|
7,043
|
|
Undeveloped
|
|
447,989
|
|
240,361
|
|
133,412
|
|
74,259
|
|
39,592
|
Total
Proved
|
|
587,580
|
|
356,108
|
|
231,807
|
|
159,846
|
|
115,467
|
Probable
|
|
690,954
|
|
321,385
|
|
173,324
|
|
102,421
|
|
64,067
|
Total Proved plus
Probable
|
|
1,278,533
|
|
677,493
|
|
405,131
|
|
262,267
|
|
179,534
|
Notes:
|
|
(1)
|
Columns may not add
due to rounding.
|
(2)
|
It should not
be assumed that the undiscounted and discounted future net revenues
estimated by GLJ represent the fair market value of the
reserves.
|
GLJ employed the following pricing, exchange rate and inflation
rate assumptions as of January 1,
2018 in the GLJ Report in estimating Cequence's reserves
data using forecast prices and costs:
|
|
Natural
Gas
|
|
Light Crude
Oil
|
|
Pentanes
Plus
|
|
|
|
|
|
|
Henry Hub
|
|
AECO Gas
Price
|
|
WTI
|
|
Edmonton
|
|
Edmonton
|
|
Inflation
Rates
|
|
Exchange
Rate
|
Year
|
|
($US/MMBtu)
|
|
($Cdn/MMBtu)
|
|
($US/bbl)
|
|
($Cdn/bbl)
|
|
($Cdn/bbl)
|
|
%/year
|
|
($US/$Cdn)
|
Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2.85
|
|
2.20
|
|
59.00
|
|
70.25
|
|
76.42
|
|
2.0
|
|
0.790
|
2019
|
|
3.00
|
|
2.54
|
|
59.00
|
|
70.25
|
|
74.68
|
|
2.0
|
|
0.790
|
2020
|
|
3.25
|
|
2.88
|
|
60.00
|
|
70.31
|
|
74.38
|
|
2.0
|
|
0.800
|
2021
|
|
3.50
|
|
3.24
|
|
63.00
|
|
72.84
|
|
77.16
|
|
2.0
|
|
0.810
|
2022
|
|
3.70
|
|
3.47
|
|
66.00
|
|
75.61
|
|
79.88
|
|
2.0
|
|
0.820
|
2023
|
|
3.86
|
|
3.58
|
|
69.00
|
|
78.31
|
|
82.53
|
|
2.0
|
|
0.830
|
2024
|
|
3.94
|
|
3.66
|
|
72.00
|
|
81.93
|
|
86.14
|
|
2.0
|
|
0.830
|
2025
|
|
4.02
|
|
3.73
|
|
75.00
|
|
85.54
|
|
89.76
|
|
2.0
|
|
0.830
|
2026
|
|
4.10
|
|
3.80
|
|
77.33
|
|
88.35
|
|
92.57
|
|
2.0
|
|
0.830
|
2027
|
|
4.18
|
|
3.88
|
|
78.88
|
|
90.22
|
|
94.43
|
|
2.0
|
|
0.830
|
Thereafter escalation
rate of 2%
|
The following table summarizes the elements of future net
revenue attributable to reserves estimated using forecast prices
and costs.
|
Revenue
($000s)
|
|
Royalties
($000s)
|
|
Operating
Costs
($000s)
|
|
Development
Costs ($000s)
|
|
Abandonment
and
Reclamation
Costs ($000s)
|
|
Future Net
Revenue
Before
Income
Taxes
($000s)
|
|
Income
Taxes
($000s)
|
|
Future Net
Revenue
After
Income
Taxes
($000s)
|
Proved
Reserves
|
1,888,733
|
|
133,308
|
|
647,023
|
|
489,366
|
|
31,457
|
|
587,580
|
|
-
|
|
587,580
|
Proved Plus
Probable Reserves
|
4,162,266
|
|
340,099
|
|
1,387,685
|
|
853,490
|
|
49,595
|
|
1,531,396
|
|
252,863
|
|
1,278,533
|
Future Net Revenue by Product Type
Reserves
Category
|
|
Product
Type
|
|
Future Net Revenue
Before
Income Taxes (3)
(discounted at 10% per
year) ($000s)
|
|
Unit Value
$/boe
|
|
Unit Value
$/MMcf
|
Proved
Reserves
|
|
|
|
|
|
|
|
|
|
|
Light and Medium Oil
(1)
|
|
25,713
|
|
13.83
|
|
2.31
|
|
|
Conventional Natural
Gas (2)
|
|
37,169
|
|
3.92
|
|
0.65
|
|
|
Shale Natural
Gas
|
|
168,925
|
|
4.01
|
|
0.67
|
|
|
Total
|
|
231,807
|
|
4.33
|
|
0.72
|
Proved Plus
Probable
Reserves
|
|
Light and Medium Oil
(1)
|
|
37,401
|
|
12.93
|
|
2.15
|
|
|
Conventional
Natural
Gas (2)
|
|
72,763
|
|
3.89
|
|
0.65
|
|
|
Shale Natural
Gas
|
|
341,427
|
|
4.07
|
|
0.68
|
|
|
Total
|
|
451,591
|
|
4.28
|
|
0.71
|
Notes:
|
|
(1)
|
Includes solution gas
and other by-products
|
(2)
|
Including by-products
but excluding solution gas
|
(3)
|
Other Company revenue
and costs not related to a specific production group have been
allocated proportionately to production groups. Unit values
are based on Company Net Reserves.
|
About Cequence
Cequence is a publicly traded Canadian energy company involved
in the acquisition, exploitation, exploration, development and
production of natural gas and crude oil in western Canada. Further information about Cequence may
be found in its continuous disclosure documents filed with Canadian
securities regulators at www.sedar.com.
Forward-looking Statements or Information
Certain statements included in this press release constitute
forward-looking statements or forward-looking information under
applicable securities legislation. Such forward-looking statements
or information are provided for the purpose of providing
information about management's current expectations and plans
relating to the future. Readers are cautioned that reliance on such
information may not be appropriate for other purposes, such as
making investment decisions. Forward-looking statements or
information typically contain statements with words such as
"believe", "expect", "plan", "estimate", "project" or similar words
suggesting future outcomes or statements regarding an outlook.
Forward-looking statements or information in this press release may
include, but are not limited to, statements or information with
respect to: the Company's guidance and forecasts and
expectations regarding market access for the Company's natural gas
production; reserves quantities and discounted net present value of
future net cash flow from such reserves; future drilling and
capital expenditure expectations; expected netbacks to be derived
from hedging activities; future water handling costs and operating
costs. Forward-looking statements or information are based on a
number of factors and assumptions which have been used to develop
such statements and information but which may prove to be
incorrect. Although the Company believes that the expectations
reflected in such forward-looking statements or information are
reasonable, undue reliance should not be placed on forward-looking
statements because the Company can give no assurance that such
expectations will prove to be correct. In addition to other factors
and assumptions which may be identified in this press release,
assumptions have been made regarding, among other things: the
impact of increasing competition; the timely receipt of any
required regulatory approvals; the ability of the Company to obtain
qualified staff, equipment and services in a timely and cost
efficient manner; the ability of the operator of the projects which
the Company has an interest in to operate the field in a safe,
efficient and effective manner; the ability of the Company to
obtain financing on acceptable terms; field production rates and
decline rates; the ability to replace and expand oil and natural
gas reserves through acquisition, development of exploration; the
timing and costs of pipeline, storage and facility construction and
expansion and the ability of the Company to secure adequate product
transportation; future oil and natural gas prices; currency,
exchange and interest rates; the regulatory framework regarding
royalties, taxes and environmental matters; and the ability of the
Company to successfully market its oil and natural gas products.
Readers are cautioned that the foregoing list is not exhaustive of
all factors and assumptions which have been used.
Forward-looking statements or information are based on
current expectations, estimates and projections that involve a
number of risks and uncertainties which could cause actual results
to differ materially from those anticipated by the Company and
described in the forward-looking statements or information. These
risks and uncertainties may cause actual results to differ
materially from the forward-looking statements or information. The
material risk factors affecting the Company and its business are
contained in the Company's Annual Information Form which is
available on SEDAR at www.sedar.com.
The forward-looking statements or information contained in
this press release are made as of the date hereof and the Company
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 unless required by
applicable securities laws. The forward-looking statements or
information contained in this press release are expressly qualified
by this cautionary statement.
Additional Advisories
The press release contains references to terms commonly used
in the oil and gas industry.
Total revenue is a non-GAAP term that represents production
revenue gross of royalties and including realized gain (loss) on
commodity contracts. Management utilizes this measure to analyze
revenue and commodity pricing and its impact on operating
performance.
Funds flow from operations is a non-GAAP term that represents
cash flow from operating activities before adjustments for
decommissioning liability expenditures, proceeds from the sale of
commodity contracts and changes in non-cash working capital. The
Company evaluates its performance based on earnings and funds flow
from operations. The Company considers funds flow from operations
to be a key measure as it demonstrates the Company's ability to
generate the cash flow necessary to fund future growth through
capital investment and to repay debt. The Company's calculation of
funds flow from operations may not be comparable to that reported
by other companies. Funds flow from operations per share is
calculated using the same weighted average number of shares
outstanding used in the calculation of income (loss) per
share.
Operating and cash netback is not defined by IFRS in
Canada and is referred to as a
non-GAAP measure. Operating netback equals total revenue less
royalties, operating costs and transportation costs. Cash netback
equals the operating netback less general and administrative
expenses and interest expense. Management utilizes these measures
to analyze operating performance.
FD&A costs and F&D costs have been calculated in
accordance with NI 51-101. F&D costs refers to all current year
net capital expenditures, excluding property acquisitions and
dispositions with associated reserves, and including changes in FDC
on a proved or proved plus probable basis. FD&A costs
incorporate both costs and associated reserve additions related to
acquisitions net of any dispositions during the year. Further
information on how the Company calculates F&D and FD&A
costs is available in the Company's Annual Information Form filed
on SEDAR. Management uses F&D costs as a measure to assess the
performance of the Company's resources required to locate and
extract new hydrocarbon reservoirs. The aggregate of the
exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future
development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
FD&A and F&D costs used by Cequence may not be comparable
to similar measures used by other issuers.
Recycle ratio is measured by dividing the operating netback
by appropriate F&D or FD&A costs per boe for the year.
Operating netback is calculated using production revenues,
including realized gains and losses on commodity hedging, less
royalties, transportation and operating expenditures, calculated on
a per boe equivalent basis. Reserve replacement ratio measures the
amount of reserves added to a Company`s reserve base during the
year relative to the amount of oil and gas produced. Management
uses these oil and gas metrics for its own performance measurements
and to provide shareholders with measures to compare the Company's
performance over time.
Non-GAAP measures do not have a standardized meaning
prescribed by IFRS and are therefore unlikely to be comparable to
similar measures presented by other issuers.
This news release contains estimates of the net present value
of the Company's future net revenue from its reserves. Such amounts
do not represent the market value of the Company's
reserves.
BOEs are presented on the basis of one BOE for six Mcf of
natural gas. Disclosure provided herein in respect of BOEs may be
misleading, particularly if used in isolation. A BOE conversion
ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
For fiscal 2017 the ratio between the average price of West
Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was
approximately 17:1 ("Value Ratio"). The Value Ratio is obtained
using the 2017 WTI average price of $50.81 (US$/Bbl) for crude oil and the 2017 NYMEX
average price of $3.02(US$/MMbtu) for
natural gas. This Value Ratio is significantly different from the
energy equivalency ratio of 6:1 and using a 6:1 ratio would be
misleading as an indication of value.
The Company's estimate that it has 50 net Montney locations on its West Simonette
lands. Including in the 50 locations are 26 locations
included in the GLJ report and 24 additional wells identified by
management to be prospective. The Company identifies 24 net
Dunvegan oil wells prospective on
its land. There are 8 wells identified in the GLJ report and
the remainder are based on internal estimates. Unbooked
locations do not do not have attributed reserves and there is no
certainty that if these locations would result in additional oil
and gas reserves or production.
The TSX has neither approved nor disapproved the contents of
this news release.
SOURCE Cequence Energy Ltd.