CALGARY, March 5, 2015 /CNW/ - Cequence Energy Ltd.
("Cequence" or the "Company") (TSX: CQE) is pleased to announce its
operating and financial results for the periods ended December 31, 2014, an operational update and the
results of its year-end independent reserve evaluation. The
Company's Audited Consolidated Financial Statements and
Management's Discussion and Analysis available at
cequence-energy.com and on SEDAR at www.sedar.com.
Highlights
Highlights for 2014 include:
- Increased annual funds flow by 38 percent to $70.7 million or $0.33 per share;
- Increased annual average production by 7 percent to 10,932
boepd;
- Reduced fourth quarter operating costs by 9 percent over Q4
2013 to $6.67 per boe;
- Realized a gain of $92 million on
the disposition of the Ansell property for $140 million;
- Maintained a strong balance sheet through declining commodity
prices with a trailing debt to cash flow ratio of 1.0 times;
- Initiated a 13-well horizontal development program at Simonette
including successfully executing multi-well pad drilling and more
intense completion techniques;
- Efficiently added reserves with proved plus probable finding,
development and acquisition costs ("FD&A costs") of
$10.26 and proved FD&A
costs of $3.97;
- Increased proved developed producing reserves by 16 percent
from the prior year to 18.7 mmboe;
- Increased proved plus probable reserves to 118 mmboe with an
NPV 10% of $854 million; and
- Achieved current production of 12,500 boepd with 2,700 boepd of
production tested and awaiting tie-in or shut-in due to
infrastructure constraints.
"Our drive to become a focused Deep Basin Montney producer
continued in 2014." said Paul
Wanklyn, President and CEO. "We monetized our Ansell
property for a significant gain and, despite losing 1,600 boepd
through the sale of the property, Cequence achieved yearly average
production of 10,932 boepd or 7 percent growth over 2013.
Important changes were made to our completion methods since Q1 2014
which resulted in the successful completion of 10 Montney wells and
3 Cretaceous wells through our fall/winter drilling program. We are
extremely pleased with both the execution success achieved by our
team, and the initiation of pad style drilling operations at our
Simonette Field"
Operations Update
During the winter program Cequence drilled 13 gross (10.95 net)
horizontal wells including 10 gross (9.0 net) Montney wells from three separate pad
locations. Drilling performance continues to improve, with
recent Montney pad wells six days
faster than earlier pad wells. Completion intensity was
increased to 1.0 tonne of sand per lateral meter compared to
historical stimulations of 0.5 tonne of sand per lateral
meter. This 100 percent increase in completion intensity, was
accomplished with only a 10 percent increase in average completion
costs. The last 3 wells drilled from the 1-32 padsite however
had an average well cost of $8.7 MM
per well or 8 percent lower than 2013/14 completion intensity
wells. As a result of the development style of this year's
capital program, seven of the 10 Montney completions were flowed in
line to sales during clean up.
Montney Well Results
Cumulative Production
Rates
|
|
|
Final Test
Rate
|
IP 30
Production
|
Pad
|
Wells
|
Gas
|
Free
Condensate
|
Gas
|
Free
Condensate
|
|
#
|
MMCFD
|
BBLD
|
bbl/mmcf
|
MMCFD
|
BBLD
|
bbl/mmcf
|
|
|
|
|
|
|
|
|
01-32
|
6
|
33.3
|
1695
|
50.9
|
26.5
|
848
|
32.0
|
|
|
|
|
|
|
|
|
12-26
|
2
|
12.4
|
222
|
17.9
|
9.5
|
156
|
16.4
|
|
|
|
|
|
|
|
|
15-15
|
2
|
13.6
|
368
|
27.1
|
Forecast on
Production March 15
|
|
|
|
|
|
|
|
|
Average per
well
|
5.9
|
229
|
38.8
|
4.5
|
126
|
28.0
|
Dunvegan and Falher Well
Results
Production
Rates
|
|
|
Final Test
Rate
|
IP 30
Production
|
Well
|
Zone
|
Gas
|
Free
Condensate
|
Gas
|
Free
Condensate
|
|
|
MMCFD
|
BBLD
|
bbl/mmcf
|
MMCFD
|
BBLD
|
bbl/mmcf
|
|
|
|
|
|
|
|
|
11-12
|
Dunvegan
|
6.8
|
118
|
17.4
|
8.1
|
174
|
21.5
|
|
|
|
|
|
|
|
|
8-18
|
Falher
|
2.1
|
15
|
7.1
|
1.6
|
13
|
8.2
|
|
|
|
|
|
|
|
|
2-11
|
Dunvegan
|
8.9
|
113
|
12.7
|
On Production March
4
|
|
|
|
|
|
|
|
|
Average per
well
|
5.9
|
83
|
14.1
|
4.9
|
94
|
19.2
|
Production and Facilities
Cequence completed the expansion of its Simonette 13-11-62-27W5
facility in January resulting in current capacity of 100 mmcfd.
The Simonette field was down for 7 days in January,
associated with the final installation of the new equipment and was
re-started on January
13th, 2015. Since January 15th, Cequence has averaged approximately
12,200 boe per day despite pipeline maintenance restrictions on the
TCPL system and related increased industry volume constraints that
cascaded onto the Alliance/Aux Sable system. The TCPL
Pipeline maintenance impacts may last until Q3 2015 and will
restrict peak production volumes from the Simonette property.
Current field estimated production is 12,500 boed with 1,200
boed of net tested production expected to be tied-in in mid-March,
with another 1,500 boed shut-in due to infrastructure capacity
restrictions. Despite these curtailments and a strategically
reduced capital budget, Cequence expects production to average
11,500 boed for the year, or a 5 percent increase compared to
2014.
Financial and Operating Highlights
(000's except per
share and per unit amounts)
|
Three months
ended
December
31,
|
Twelve months
ended
December
31,
|
|
|
2014
|
2013
|
%
Change
|
2014
|
2013
|
%
Change
|
Financial
($)
|
|
|
|
|
|
|
|
Production revenue
(1)
|
|
25,566
|
28,483
|
(10)
|
136,893
|
105,617
|
30
|
Comprehensive income
(loss)
|
|
(4,422)
|
(827)
|
(435)
|
79,368
|
(2,613)
|
3,137
|
Per share -
basic
|
|
(0.02)
|
(0.00)
|
n/a
|
0.38
|
(0.01)
|
3,900
|
Per share -
diluted
|
|
(0.02)
|
(0.00)
|
n/a
|
0.37
|
(0.01)
|
3,800
|
Funds flow from
operations (2)
|
|
13,745
|
14,855
|
(7)
|
70,650
|
51,312
|
38
|
Per share,
basic
|
|
0.07
|
0.07
|
-
|
0.33
|
0.25
|
32
|
Per share,
diluted
|
|
0.06
|
0.07
|
(14)
|
0.33
|
0.25
|
32
|
Production
volumes
|
|
|
|
|
|
|
|
Natural gas
(Mcf/d)
|
|
49,265
|
53,433
|
(8)
|
55,826
|
52,705
|
6
|
Crude oil
(bbls/d)
|
|
97
|
119
|
(18)
|
118
|
125
|
(6)
|
Natural gas liquids
(bbls/d)
|
|
541
|
569
|
(5)
|
583
|
524
|
11
|
Condensate
(bbls/d)
|
|
872
|
800
|
9
|
927
|
750
|
24
|
Total
(boe/d)
|
|
9,720
|
10,394
|
(6)
|
10,932
|
10,183
|
7
|
Sales
prices
|
|
|
|
|
|
|
|
Natural gas,
including realized hedges ($/Mcf)
|
|
3.92
|
3.82
|
3
|
4.54
|
3.57
|
27
|
Crude oil
($/bbl)
|
|
73.15
|
78.56
|
(7)
|
89.76
|
86.46
|
4
|
Natural gas liquids
($/bbl)
|
|
29.67
|
44.46
|
(33)
|
41.10
|
39.72
|
3
|
Condensate
($/bbl)
|
|
70.59
|
88.44
|
(20)
|
94.04
|
92.52
|
2
|
Total
($/boe)
|
|
28.59
|
29.79
|
(4)
|
34.31
|
28.42
|
21
|
Netback
($/boe)
|
|
|
|
|
|
|
|
Price
|
|
28.59
|
29.79
|
(4)
|
34.31
|
28.42
|
21
|
Royalties
|
|
(1.25)
|
(1.85)
|
(32)
|
(3.51)
|
(2.32)
|
51
|
Transportation
|
|
(1.48)
|
(1.62)
|
(9)
|
(1.48)
|
(1.60)
|
(8)
|
Operating
costs
|
|
(6.67)
|
(7.33)
|
(9)
|
(7.63)
|
(7.66)
|
-
|
Operating
netback
|
|
19.19
|
18.99
|
1
|
21.69
|
16.84
|
29
|
General and
administrative
|
|
(2.27)
|
(1.65)
|
38
|
(2.21)
|
(1.95)
|
13
|
Interest(5)
|
|
(1.87)
|
(1.77)
|
6
|
(1.87)
|
(0.93)
|
101
|
Cash
netback
|
|
15.05
|
15.57
|
(3)
|
17.61
|
13.96
|
26
|
Capital
expenditures ($)
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
56,472
|
51,578
|
9
|
180,215
|
117,909
|
53
|
Net acquisitions
(dispositions) (4)
|
|
(2,381)
|
(47)
|
4,966
|
(150,782)
|
(2,675)
|
5,537
|
Total capital
expenditures
|
|
54,091
|
51,531
|
5
|
29,433
|
115,234
|
(74)
|
Net debt and
working capital (deficiency) (3)
|
|
(71,354)
|
(111,433)
|
(36)
|
(71,354)
|
(111,433)
|
(36)
|
Weighted average
shares outstanding
|
|
|
|
|
|
|
|
Basic
|
|
211,028
|
210,917
|
-
|
210,990
|
207,950
|
1
|
Diluted
|
|
212,069
|
210,917
|
1
|
214,092
|
207,950
|
3
|
(1)
|
Production 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 and working
capital (deficiency) is calculated as cash and net working capital
less commodity contract assets and liabilities, demand credit
facilities, principal value of senior notes and excluding other
liabilities.
|
(4)
|
Represents the cash
proceeds from the sale of assets and cash paid for the acquisition
of assets, as applicable.
|
(5)
|
Represents finance
costs less amortization on transaction costs and accretion expense
on senior notes and provisions.
|
FINANCIAL
Funds flow from operations increased to $70.7 million for 2014 compared to $51.3 million for the 2013. The increase in
funds flow from operations is due largely to higher realized oil
and natural gas prices and a 7 percent increase in production
volumes. Funds flow from operations was $13.7 million for the three months ended
December 31, 2014, compared to
$14.9 million for the three months
ended December 31, 2013. Fourth
quarter production volumes were down six percent from 2013 and
average sales prices decreased by four percent from the prior
year.
Comprehensive income for the year ended December 31, 2014 was $79.4 million compared to a $2.6 million loss in 2013. The increase in
earnings is due to gains realized on the sale of oil and gas
properties in the year of $99.8
million and higher commodity prices, offset partially by
increases in future income taxes, depletion and impairment.
Cequence recorded a comprehensive loss of $4.4 million for the fourth quarter of 2014
compared to comprehensive loss of $0.8
million in the same period in 2013. The loss in the fourth
quarter of 2014 is a result of impairment charges of $18.4 million offset by an unrealized hedging
gain $10.6 million.
Capital expenditures, prior to acquisition and dispositions,
were $56.5 million in the fourth
quarter of 2014 and $180.2 million
for the year ended December 31,
2013. For the year ended December 31,
2014, Cequence participated in drilling 20 (14.9 net)
wells. Net of acquisitions and dispositions of
$150.8 million, capital expenditures
were $29.4 million for the year ended
December 31, 2014.
The Company is well positioned to weather the current period of
low commodity prices. The Company exited 2014 with available
credit facilities of $195 million
versus net debt of $71.4
million. On a trailing twelve month basis, the net
debt to cash flow ratio is 1.0 times. Net debt is comprised of
$60 million in senior notes carrying
a five year term and a working capital deficiency of $11.4 million. The Company's senior
credit facility was undrawn at December 31,
2014.
Outlook and Guidance
Balance sheet strength remains critically important to the
Company's strategy of maximizing shareholder value through
profitable growth. In response to weak commodity prices, the
Company reduced capital spending in the first half of 2015 to
$22 million and spending will
approximate cash flow over this period. Budgeted capital
expenditures for 2015 are $60 million
and will include (5.0)4.2 net horizontal wells to be drilled at
Simonette in the second half of 2015. The Company will
continue to monitor fluctuations in commodity prices and may adjust
capital spending based on the Company's hedge position and short to
medium term crude oil and natural gas prices.
Cequence anticipates production growth of five percent in 2015
based largely on the success of the 2014/15 winter drilling
program. Annual production volumes are expected to average
11,500 boepd for the year ended December
31, 2014.
First quarter production is expected to average 11,500 boepd,
compared to 12,500-13,000 boepd as previously guided due to
onstream delays and recent maintenance to the TransCanada system
and the resulting spillover of production volumes filling existing
Alliance capacity. Cequence expects the maintenance
issues to be ongoing through September
2015.
The Company has hedged approximately half of its 2015 natural
gas production at an average price of $3.84
Cdn per mcf and will continue to actively hedge production
to protect future capital spending programs. Based on AECO
natural gas prices of $2.65/GJ,
annual funds flow is forecast to be approximately $40 million resulting in net debt of
approximately $90 million at
December 31, 2015.
|
|
Previous
2015
(3
months)
|
Revised
2015
(3
months)
|
Guidance
2015
|
Average production,
BOE/d (1)
|
|
12,500-13,000
|
11,500
|
11,500
|
Funds flow from
operations ($) (2)
|
|
$12,000
|
$10,000
|
$40,000
|
Funds flow from
operations per share (2)
|
|
$0.06
|
$ 0.05
|
$0.19
|
Capital expenditures,
prior to dispositions ($) (3)
|
|
$22,000
|
$22,000
|
$60,000
|
Wells
drilled
|
|
5(4.7)
|
5(4.7)
|
10(9.2)
|
Operating and
transportation costs ($ per boe)
|
|
$8.20
|
$8.80
|
$8.80
|
G&A costs ($ per
boe)
|
|
$1.90
|
$2.50
|
$2.50
|
Royalties (%
revenue)
|
|
10
|
10
|
10
|
Crude – WTI
(US$/bbl)
|
|
$50.00
|
$50.00
|
$50.00
|
Natural gas – AECO
(Cdn$/GJ)
|
|
$2.65
|
$2.65
|
$2.65
|
Period end, net debt
and working capital deficiency ($) (4)
|
|
$85,000
|
$85,000
|
$90,000
|
Basic shares
outstanding
|
|
211,000
|
211,000
|
211,000
|
Notes:
|
|
(1)
|
Average production
estimates on a per BOE basis are comprised of 84% natural gas and
16% oil and natural gas liquids.
|
(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 and working
capital (deficiency) is calculated as cash and net working capital
less commodity contract assets and liabilities, demand credit
facilities and the aggregate principal amount of the senior notes
and excluding other liabilities.
|
Reserves
The following highlights are based on the reserve
report effective December 31,
2014 (the "GLJ Report") prepared by GLJ Petroleum
Consultants ("GLJ"):
- Increased proved developed producing reserves by 16 % from the
prior year to 18.7 mmboe;
- Increased proved reserves by 3% from the prior year to 57.1
MMBOE;
- Increased proved plus probable reserves by 4% from the prior
year to 118.1 MMBOE;
- Achieved FD&A costs (including changes to FDC) of
$10.26 per boe on a proved plus
probable basis and $3.97 per boe on a
proved basis;
- Achieved F&D costs (including changes to FDC) of
$13.82 per boe on a proved plus
probable basis and $16.66 per boe on
a proved basis;
- Achieved an FD&A recycle ratio of 2.1 times based on the
2014 operating netback of $21.69;
- Net present value before income taxes of the Company's proved
plus probable reserves is $854 million or $4.05 per share (using a discount rate of 10%);
and
- Replaced 227 percent of production with proven plus probable
reserve additions.
In accordance with NI 51101, GLJ prepared the GLJ Report for the
oil, natural gas liquids and natural gas reserves attributable to
the properties of Cequence.
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. 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
|
|
NGL
|
|
Natural
Gas
|
|
Total Oil
Equivalent
|
Reserves
Category
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
Gross
|
Net
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(MMcf)
|
|
(MBOE)
|
|
(MBOE)
|
Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
Producing
|
1,595
|
1,106
|
|
997
|
854
|
|
96,604
|
84,834
|
|
18,693
|
16,099
|
|
Developed
Non-Producing
|
523
|
363
|
|
273
|
240
|
|
25,423
|
22,176
|
|
5,033
|
4,299
|
|
Undeveloped
|
3,537
|
2,586
|
|
1,774
|
1,643
|
|
168,474
|
148,229
|
|
33,390
|
28,934
|
Total
Proved
|
5,655
|
4,055
|
|
3,043
|
2,737
|
|
290,500
|
255,239
|
|
57,115
|
49,332
|
Probable
|
6,315
|
4,328
|
|
3,200
|
2,926
|
|
308,409
|
268,558
|
|
60,917
|
52,014
|
Total Proved plus
Probable
|
11,971
|
8,383
|
|
6,243
|
5,663
|
|
598,909
|
523,797
|
|
118,032
|
101,346
|
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
Reserves
Category
|
Before Future Income
Tax Expenses Discounted at (%/year)
|
|
0
|
|
5
|
|
10
|
|
15
|
|
20
|
|
10
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
($/mcfe)
|
|
Proved
|
|
|
|
|
|
|
|
Developed
Producing
|
288,076
|
232,727
|
195,984
|
170,101
|
150,970
|
2.03
|
|
Developed
Non-Producing
|
88,906
|
68,135
|
55,167
|
46,415
|
40,140
|
2.14
|
|
Undeveloped
|
471,949
|
296,967
|
196,335
|
133,513
|
91,870
|
1.13
|
Total
Proved
|
848,931
|
597,829
|
447,485
|
350,029
|
282,980
|
1.51
|
Probable
|
1,157,793
|
651,276
|
406,738
|
270,841
|
187,791
|
1.30
|
Total Proved plus
Probable
|
2,006,724
|
1,249,105
|
854,223
|
620,870
|
470,771
|
1.40
|
|
|
|
|
|
|
|
Reserves
Category
|
|
After Future Income
Tax Expenses Discounted at (%/year)
|
0
|
|
5
|
|
10
|
|
15
|
|
20
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
Proved
|
|
|
|
|
|
|
Developed
Producing
|
288,076
|
232,727
|
|
195,984
|
170,101
|
150,970
|
|
Developed
Non-Producing
|
88,906
|
68,135
|
55,167
|
46,415
|
40,140
|
|
Undeveloped
|
412,255
|
265,896
|
179,061
|
123,389
|
85,675
|
Total
Proved
|
789,237
|
566,758
|
430,211
|
339,905
|
276,786
|
Probable
|
867,481
|
481,142
|
294,925
|
191,954
|
129,495
|
Total Proved plus
Probable
|
1,656,719
|
1,047,900
|
725,137
|
531,859
|
406,281
|
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,
2015 in the GLJ Report in estimating Cequence's reserves
data using forecast prices and costs:
Year
|
|
Natural
Gas
|
|
Light Crude
Oil
|
|
Pentanes
Plus
|
|
Inflation
Rates
|
|
|
Exchange
Rate
|
|
Henry Hub
|
|
AECO Gas
Price
|
|
WTI
|
|
Edmonton
|
|
Edmonton
|
|
($US/MMBtu)
|
|
($Cdn/MMBtu)
|
|
($US/bbl)
|
|
($Cdn/bbl)
|
|
($Cdn/bbl)
|
|
%/year
|
|
($US/$Cdn)
|
Forecast
|
|
|
|
|
|
|
|
2015
|
|
3.31
|
3.31
|
62.50
|
|
64.71
|
|
69.24
|
2.0
|
0.850
|
2016
|
3.75
|
3.77
|
75.00
|
|
80.00
|
85.60
|
2.0
|
0.875
|
2017
|
4.00
|
4.02
|
80.00
|
85.71
|
91.71
|
2.0
|
0.875
|
2018
|
4.25
|
4.27
|
85.00
|
91.43
|
97.83
|
2.0
|
0.875
|
2019
|
4.50
|
4.53
|
90.00
|
97.14
|
103.94
|
2.0
|
0.875
|
2020
|
4.75
|
4.78
|
95.00
|
102.86
|
110.06
|
2.0
|
0.875
|
2021
|
5.00
|
5.03
|
98.54
|
106.18
|
113.62
|
2.0
|
0.875
|
2022
|
5.25
|
5.28
|
100.51
|
108.31
|
115.89
|
2.0
|
0.875
|
2023
|
5.50
|
5.53
|
102.52
|
110.47
|
118.20
|
2.0
|
0.875
|
2024
|
5.68
|
5.71
|
104.57
|
112.67
|
120.56
|
2.0
|
0.875
|
Thereafter escalation
rate of 2%
|
FD&A and F&D both including and excluding FDC have been
calculated in accordance with NI 51-101. Cequence's finding,
development and acquisition costs are as follows:
|
|
|
|
Proved
|
|
Proved
Plus
Probable
|
FD&A Including
Change in FDC
|
|
|
|
2014 FD&A Costs
($000s)
|
29,433
|
29,433
|
|
2014 Change in FDC
($000s)
|
(5,871)
|
(63,886)
|
|
2014 Capital
Expenditures including change in FDC ($000s)
|
23,562
|
93,319
|
|
2014 Reserve
Additions (MBOE)
|
5,939
|
9,091
|
|
2014 FD&A
Including Change in FDC ($/BOE)
|
3.97
|
10.26
|
|
3 year average
FD&A Including Change in FDC ($/BOE)
|
11.68
|
10.77
|
F&D Including
Change in FDC
|
|
|
|
2014 F&D Costs
($000s)
|
180,215
|
180,215
|
|
2014 Change in FDC
($000s)
|
30,625
|
133,859
|
|
2014 Capital
Expenditures including change in FDC ($000s)
|
210,840
|
314,074
|
|
2014 Reserve
Additions (MBOE)
|
12,657
|
22,727
|
|
2014 F&D
Including Change in FDC ($/BOE)
|
16.66
|
13.82
|
|
3 year average
F&D Including Change in FDC ($/BOE)
|
14.12
|
11.63
|
|
|
|
FDC – December 31,
2014 ($000s)
|
381,427
|
849,135
|
FDC – December 31,
2013 ($000s)
|
387,298
|
785,249
|
2014 Change in FDC
($000s)
|
(5,871)
|
63,886
|
FDC Related to 2014
Net Acquisitions (Dispositions) ($000s)
|
36,496
|
69,973
|
2014 Change in FDC
Excluding FDC on Net Acquisitions (Dispositions) ($000s)
|
30,625
|
133,859
|
Note:
|
|
(1)
|
In addition to
F&D costs, Cequence also calculates FD&A costs which
incorporate both the costs and associated reserve additions related
to acquisitions net of any dispositions during the year. Since
acquisitions can have a significant impact on Cequence's annual
reserve replacement costs, the Company believes that FD&A costs
provide a more meaningful portrayal of Cequence's cost
structure.
|
(2)
|
Capital expenditures
for the FD&A calculation include cash expenditures on property
and equipment and exploration and evaluation expenditures of
$180,215, net cash expenditures on property acquisition and
dispositions of ($150,782).
|
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
"anticipate", "believe", "expect", "plan", "intend", "estimate",
"propose", "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 its guidance and
forecasts: business strategy and objectives; the Company's 2015
capital program; development, exploration, acquisition and
disposition plans, including the anticipated benefits resulting
therefrom and the timing thereof; reserve quantities and the
discounted present value of future net cash flows from such
reserves; future production levels; facility expansion and
drillings plans; the timing of the impacts of the TransCanada
Pipeline system; expected future oil and gas prices; and the timing
of well completions. 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. Netback is not defined by IFRS
in Canada and is referred to as a
non-GAAP measure. Netbacks equal total revenue less
royalties, operating costs and transportation costs.
Management utilizes this measure to analyze 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.
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.
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.
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 2014, the ratio between the average price of West
Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was
approximately 22:1 ("Value Ratio"). The Value Ratio is obtained
using the 2014 WTI average price of $93.03 (US$/Bbl) for crude oil and the 2014 NYMEX
average price of $4.26 (US$/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 TSX has neither approved nor disapproved the contents of
this news release.
SOURCE Cequence Energy Ltd.