Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is
pleased to announce its operating and financial results for the
fourth quarter and year ended December 31, 2018, as well as its
year-end reserve evaluation as prepared by its qualified
independent reserve evaluator. 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.
2018 Highlights
- Achieved full year 2018 production
of 6,507 boe/d and increased liquids weighting to 23% up from 17%
in 2017;
- Funds flow from operations in 2018
was $13.1 million or $0.53 per share based on year end 2018
outstanding shares;
- Fourth quarter 2018 oil production
increased by 160% over the same period in 2017;
- Strengthened the Company’s balance
sheet through a $8.6 million rights offering and renegotiation of
the $60 million term debt with a 4 year maturity and 5% interest
rate;
- Continued successful step out
drilling of the Company’s Dunvegan oil pool. Drilled,
completed, and tied in 5 gross (4 net) horizontal Dunvegan oil
wells and 1 gross (1 net) successful stratigraphic oil well
test;
- Corporate 10% proved developed
producing reserve value of $74 million includes a $20.6 million
unutilized take or pay short fall under this scenario.
Additional Cequence production volumes from the total proved and
proved plus probable cases would alleviate this shortfall;
- The Corporate net asset value per
share at a 10% discount rate using GLJ January 1, 2019 prices and
year end 2018 net debt is $4.31/share total proved and $15.19/share
proved plus probable;
- Achieved a Corporate proved plus
probable FD&A of $3.50/boe;
- Before production, Dunvegan oil
proved developed producing, total proved, and proved plus probable
reserves increased by 303%, 74%, and 90% respectively to 1.6 MMboe,
2.9 MMboe and 5.3 MMboe;
- Dunvegan oil total proven and
proven plus probable net present values at 10% discount rate are
$41.8 million and $74.7 million respectively using GLJ January 1,
2019 prices; and
- Added market diversity away from
AECO prices with 10,850 GJ/d of production sold at Dawn beginning
April 1, 2018. Realized gas price in 2018 was $2.40/mcf, an
increase of 58% over the AECO 2018 spot price of $1.52/mcf.
Comparative financial and operating information
for 2018 and 2017 are as follows:
|
(000’s except per share and per unit amounts) |
Three months endedDecember
31, |
Twelve months endedDecember
31, |
|
|
2018 |
|
2017 |
|
% Change |
2018 |
|
2017 |
|
% Change |
|
FINANCIAL |
|
|
|
|
|
|
| Total revenue(1),
(5) |
12,184 |
|
13,585 |
|
(10 |
) |
58,921 |
|
65,836 |
|
(11 |
) |
|
Comprehensive loss |
(3,802 |
) |
(6,638 |
) |
(43 |
) |
(9,699 |
) |
(99,362 |
) |
(90 |
) |
| Per share
– basic and diluted (6) |
(0.16 |
) |
(0.54 |
) |
(70 |
) |
(0.61 |
) |
(8.09 |
) |
(92 |
) |
| Funds
flow from operations (2), (5) |
2,071 |
|
1,583 |
|
31 |
|
13,087 |
|
19,329 |
|
(32 |
) |
| Per
share, basic and diluted (6), (7) |
0.08 |
|
0.13 |
|
(38 |
) |
0.82 |
|
1.57 |
|
(48 |
) |
| Capital
expenditures, before acquisitions (dispositions) |
13,397 |
|
5,593 |
|
140 |
|
23,800 |
|
25,857 |
|
(8 |
) |
| Capital
expenditures, including acquisitions (dispositions) |
12,463 |
|
1,316 |
|
847 |
|
20,937 |
|
21,580 |
|
(3 |
) |
| Net debt
(3), (5) |
(72,103 |
) |
(68,501 |
) |
5 |
|
(72,103 |
) |
(68,501 |
) |
5 |
|
| Weighted
average shares outstanding – basic (6) |
24,553 |
|
12,277 |
|
100 |
|
15,942 |
|
12,277 |
|
30 |
|
| Weighted
average shares outstanding – diluted (6) |
24,553 |
|
12,277 |
|
100 |
|
15,942 |
|
12,277 |
|
30 |
|
| Common
shares outstanding – end of period |
24,553 |
|
12,277 |
|
100 |
|
24,553 |
|
12,277 |
|
100 |
|
|
OPERATING |
|
|
|
|
|
|
|
Production volumes |
|
|
|
|
|
|
| Natural
gas (Mcf/d) |
27,645 |
|
33,331 |
|
(17 |
) |
30,098 |
|
40,466 |
|
(26 |
) |
| Crude
oil (bbls/d) |
736 |
|
283 |
|
160 |
|
763 |
|
344 |
|
122 |
|
| Natural
gas liquids (bbls/d) |
227 |
|
257 |
|
(12 |
) |
250 |
|
254 |
|
(2 |
) |
|
Condensate (bbls/d) |
427 |
|
617 |
|
(31 |
) |
478 |
|
797 |
|
(40 |
) |
|
Total (boe/d) |
5,997 |
|
6,713 |
|
(11 |
) |
6,507 |
|
8,139 |
|
(20 |
) |
|
Sales prices |
|
|
|
|
|
|
| Natural
gas, including realized hedges ($/Mcf) |
2.91 |
|
2.33 |
|
25 |
|
2.49 |
|
2.53 |
|
(2 |
) |
| Crude
oil and condensate, including realized hedges ($/bbl) |
37.74 |
|
66.73 |
|
(43 |
) |
61.89 |
|
61.44 |
|
1 |
|
| Natural
gas liquids ($/bbl) |
35.37 |
|
38.55 |
|
(8 |
) |
38.18 |
|
30.72 |
|
24 |
|
|
Total ($/boe) |
22.08 |
|
22.00 |
|
1 |
|
24.81 |
|
22.16 |
|
12 |
|
|
Netback ($/boe) |
|
|
|
|
|
|
| Price,
including realized hedges |
22.08 |
|
22.00 |
|
1 |
|
24.81 |
|
22.16 |
|
12 |
|
|
Royalties |
(1.33 |
) |
(0.63 |
) |
111 |
|
(1.67 |
) |
(1.06 |
) |
58 |
|
|
Transportation |
(3.84 |
) |
(1.66 |
) |
131 |
|
(3.01 |
) |
(1.88 |
) |
60 |
|
|
Operating costs |
(9.86 |
) |
(12.91 |
) |
(24 |
) |
(10.14 |
) |
(9.29 |
) |
9 |
|
|
Operating netback (5) |
7.05 |
|
6.80 |
|
4 |
|
9.99 |
|
9.93 |
|
1 |
|
| General
and administrative |
(2.07 |
) |
(1.88 |
) |
10 |
|
(2.22 |
) |
(1.48 |
) |
50 |
|
|
Interest (4) |
(1.42 |
) |
(2.46 |
) |
(42 |
) |
(1.98 |
) |
(2.07 |
) |
(4 |
) |
|
Cash netback (5) |
3.56 |
|
2.46 |
|
45 |
|
5.79 |
|
6.38 |
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Total revenue is presented gross of
royalties and includes realized gains (loss) on commodity
contracts.
- 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.
- Net debt is calculated as working
capital deficiency (excluding commodity contracts) plus the
principal value of the Senior Notes and Term Loan (as such terms
are defined below).
- Represents finance costs less
refinancing expenses, amortization on transaction costs, accretion
expense on Senior Notes and provisions.
- Refer to “Non-GAAP Measures”
advisory in this press release.
- On October 22, 2018, the Company’s
shareholders approved a share consolidation based on one new common
share for every 20 pre-consolidation shares. All information
relating to issued and common shares, stock options, warrants,
restricted share units and per share amounts, have been restated to
reflect the share consolidation for all periods presented.
- Funds flow per share calculated as
if the ending 24,553,000 common shares at December 31, 2018 were
outstanding for the entire period would be $0.53 per share for the
twelve months ended December 31, 2018.
Financial
Natural gas prices remained low in both 2018 and
2017 with AECO prices averaging $1.52/mcf and $2.23/mcf,
respectively. Annual funds flow from operations decreased 32% to
$13.1 million mainly due to lower natural gas prices and volumes.
The decrease was partially offset by increased crude oil,
condensate and NGL prices and oil volumes year over year. Fourth
quarter funds flow increased 31% to $2.1 million, mainly due to
increased production revenue, lower operating expenses and lower
interest expense on the Term Loan. For the twelve months ended
December 31, 2018, the Company recorded a comprehensive loss of
$9.7 million compared to $99.3 million in 2017. The decrease is due
to 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 $23.8
million ($20.9 net of dispositions) with $19.9 million focused on
wells with higher oil and liquids content. The majority of capital
was spent as follows: $16.3 million on drilling and completion
activity, $4.8 million on facilities and equipment, and $1.0
million on workovers.
On July 27, 2018 Cequence announced a series of
transactions to refinance the Company’s balance sheet and provide
greater flexibility and liquidity to execute the ongoing business
plan of the Company. Cequence entered into a second lien secured
loan agreement for a $60 million term loan facility due October 3,
2022 (the “Term Loan”) to refinance the existing $60 million
unsecured five year senior notes which were due on October 3, 2018
(the “Senior Notes”). At the same time, Cequence launched a rights
offering for holders of its common shares as of August 9, 2018 to
subscribe for 12,276,394 (post-consolidation) flow through common
shares of the Company for gross proceeds of up to $8.6 million. The
rights offering was fully subscribed for and closed on September
13, 2018.
The Company has $72.1 million in net debt as at
December 31, 2018, which is comprised of the Term Loan ($60
million) and a working capital deficiency of $12.1 million
(excluding commodity contracts). The Company also has a senior
credit facility of $7 million that remains undrawn other than
letters of credit of $1.6 million and has a maturity date May 31,
2019.
The Company has hedged approximately 26% of its
2019 estimated production, including 40% of its forecasted oil
volumes, at a price of $85.29/bbl CAD. Since April 1, 2018 the
Company has been selling 10,850 GJ/d of gas production in the Dawn
market. The Dawn marketing arrangement has provided the Company
diversification away from the volatile AECO prices for
approximately 1/3 of its gas production. For the year ended
December 31, 2018, Dawn prices averaged approximately $4.15/mcf
compared to AECO pricing of approximately $1.52/mcf.
2018 Operational and
Production
During the winter of 2017/2018 and the fourth
quarter of 2018, Cequence drilled, completed, and brought on stream
5 gross (4 net) horizontal Dunvegan oil wells as well as drilled 1
gross (1 net) vertical stratigraphic oil test well. The horizontal
wells drilled in the fourth quarter of 2018 were tied into
permanent facilities on January 10, 2019. In February 2019, the
pumps were removed from the two wells and they are both flowing.
The recent production from the fourth quarter 2018 wells are shown
in the table below.
|
|
|
January 2019 calendar day average
(gross) |
Last 10/24 Operating days February
(gross) |
|
Well UWI |
CQE % |
Oil (bbl/d) |
Gas (mcf/d) |
Oil (bbl/d) |
Gas (mcf/d) |
|
10-04-062-26W5 |
100 |
% |
266 |
650 |
310 |
1,300 |
|
16-02-062-26W5 |
100 |
% |
225 |
370 |
260 |
1,000 |
|
|
|
|
|
|
|
|
In 2018, approximately $19.9 million dollars or
84% of the Corporation’s $23.8 million capital expenditures, before
acquisitions, was spent on the Dunvegan oil program. This Dunvegan
capital included $6.4 million for drilling, $9.5 million on
completions, and $4.0 million on facilities and equipment including
the installation of an 8 inch gathering line to the new 2018
multi-well pad site as well as an upgrade to the 5-7-62-25W5 oil
handling facility to eliminate long term rental equipment. A
majority of the remaining 2018 capital spend was focused on
expanding and optimizing water disposal capacity in the Simonette
area.
For the year ended December 31, 2018, operating
costs averaged $10.14/boe in 2018, up 9% from 2017, with operating
costs down 24% in the fourth quarter to $9.86/boe as compared to
the same period of 2017. In the second half of 2017 and extending
into the first quarter of 2018, the Company had one-time expenses
associated with accelerating a water handling and disposal project
to reduce its surface water and associated costs at the Simonette
field. In the fourth quarter of 2018, a second water disposal well
and associated equipment was added in the east side of Simonette
which has further reduced water trucking and disposal costs.
Despite lower forecasted 2019 total production rates the 2019
operating costs are expected to remain between $9.50 and $10.50 per
boe.
Corporate production for the three and twelve
months ended December 31, 2018 averaged 5,997 boe/d and 6,507
boe/d, respectively, compared to production of 6,713 boe/d and
8,139 boe/d in 2017. Oil and liquids production for the same
periods increased to 1,390 bbl/d and 1,491 bbl/d, up 20% and 7%
respectively.
2018 Independent Reserve Evaluation
Matters
GLJ Petroleum Consultants (“GLJ”) prepared the
reserves report effective December 31, 2018 (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 Standards of Disclosure for Oil and Gas
Activities (“NI 51-101”). The reserves data provided in this press
release represents only a portion of the disclosure required by NI
51-101. Additional information from the GLJ Report, including all
disclosure required under NI 51-101, will be contained in the
Company’s Annual Information Form for the year ended December 31,
2018, which will be filed on SEDAR on or before March 31, 2019.
Reserves highlights of the Company include:
- Corporate reserves were 10.6 MMboe
proved developed producing, 57.0 MMboe proven, and 129.4 MMboe on a
proved plus probable basis.
- Corporate FD&A, including
changes in future development capital, was $3.50/boe on a proven
plus probable basis;
- The Corporate net asset value per
share at a 10% discount rate using GLJ January 1, 2019 prices and
year end 2018 net debt is $4.31/share total proved and $15.19/share
proved plus probable;
- Before production, Dunvegan oil
proved developed producing, total proved, and proved plus probable
reserves increased by 303%, 74%, and 90% respectively to 1.6 MMboe,
2.9 MMboe and 5.3 MMboe.
- Dunvegan oil total proven and
proven plus probable net present values at 10% discount rate are
$41.8 million and $74.7 million respectively using GLJ January 1,
2019 prices
- Undeveloped Dunvegan oil inventory
is 5.5 net proven and 10.5 net proved plus probable
locations.
- The Dunvegan oil program finding,
development, and acquisition costs inclusive of changes in booked
future development capital, was $12.64/boe proved developed
producing, $20.77/boe total proved, and $14.91/boe proved plus
probable. The 2018 operating netback for the Dunvegan oil area is
estimated at $34.74/boe which yields recycle ratios of 2.7, 1.7,
and 2.3 respectively.
- Due to lower commodity prices and
other economic factors non-core assets totaling 1.4 MMboe proved
and 2.3 MMboe proven plus probable were not assigned
reserves.
- A total of 0.31 MMboe proven and
0.51 MMboe proven plus probable reserves were sold in calendar year
2018.
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 |
|
735 |
|
615 |
|
0 |
|
0 |
|
18,615 |
|
16,961 |
|
33,153 |
|
28,325 |
|
1,259 |
|
826 |
|
10,623 |
|
8,989 |
| Developed
Non-Producing |
|
12 |
|
9 |
|
0 |
|
0 |
|
2,569 |
|
2,267 |
|
4,328 |
|
3,569 |
|
146 |
|
90 |
|
1,307 |
|
1,072 |
|
Undeveloped |
|
649 |
|
564 |
|
0 |
|
0 |
|
3,688 |
|
3,369 |
|
223,813 |
|
194,944 |
|
6,541 |
|
5,485 |
|
45,107 |
|
39,101 |
| Total
Proved |
|
1,396 |
|
1,187 |
|
0 |
|
0 |
|
24,872 |
|
22,596 |
|
261,293 |
|
226,838 |
|
7,946 |
|
6,402 |
|
57,036 |
|
49,161 |
|
Probable |
|
1,193 |
|
965 |
|
0 |
|
0 |
|
58,926 |
|
54,068 |
|
311,007 |
|
259,564 |
|
9,524 |
|
7,070 |
|
72,372 |
|
60,306 |
| Total
Proved plus Probable |
|
2,589 |
|
2,152 |
|
1 |
|
0 |
|
83,799 |
|
76,665 |
|
572,300 |
|
486,402 |
|
17,470 |
|
13,471 |
|
129,409 |
|
109,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes:
- Columns may not add due to rounding.
- "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.
- "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$) |
|
(M$) |
|
($/mcfe) |
| Proved |
|
|
|
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
90,358 |
|
81,708 |
|
74,036 |
|
67,593 |
|
62,231 |
|
1.37 |
| Developed
Non-Producing |
|
11,110 |
|
8,846 |
|
7,134 |
|
5,855 |
|
4,889 |
|
1.11 |
|
Undeveloped |
|
311,475 |
|
175,301 |
|
96,640 |
|
49,580 |
|
20,458 |
|
0.41 |
| Total
Proved |
|
412,943 |
|
265,855 |
|
177,810 |
|
123,028 |
|
87,577 |
|
0.6 |
|
Probable |
|
875,166 |
|
460,970 |
|
267,145 |
|
166,182 |
|
108,799 |
|
0.74 |
| Total
Proved plus Probable |
|
1,288,109 |
|
726,824 |
|
444,955 |
|
289,210 |
|
196,377 |
|
0.68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Reserves Category |
|
After Future Income Tax Expenses Discounted at
(%/year) |
|
|
0 |
|
5 |
|
10 |
|
15 |
|
20 |
|
|
(M$) |
|
(M$) |
|
(M$) |
|
(M$) |
|
(M$) |
| Proved |
|
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
90,358 |
|
81,708 |
|
74,036 |
|
67,593 |
|
62,231 |
| Developed
Non-Producing |
|
11,110 |
|
8,846 |
|
7,134 |
|
5,855 |
|
4,889 |
|
Undeveloped |
|
311,475 |
|
175,301 |
|
96,640 |
|
49,580 |
|
20,458 |
| Total
Proved |
|
412,943 |
|
265,855 |
|
177,810 |
|
123,028 |
|
87,577 |
|
Probable |
|
678,622 |
|
369,651 |
|
220,181 |
|
140,117 |
|
93,468 |
| Total
Proved plus Probable |
|
1,091,566 |
|
635,505 |
|
397,991 |
|
263,145 |
|
181,046 |
|
|
|
|
|
|
|
|
|
|
|
|
Notes:
- Columns may not add due to rounding.
- 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, 2019 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
3 |
|
1.85 |
|
56.25 |
|
63.33 |
|
67.67 |
|
2 |
|
0.75 |
|
2020 |
|
3.15 |
|
2.29 |
|
63 |
|
75.32 |
|
79.22 |
|
2 |
|
0.77 |
|
2021 |
|
3.35 |
|
2.67 |
|
67 |
|
79.75 |
|
83.54 |
|
2 |
|
0.79 |
|
2022 |
|
3.5 |
|
2.9 |
|
70 |
|
81.48 |
|
85.49 |
|
2 |
|
0.81 |
|
2023 |
|
3.63 |
|
3.14 |
|
72.5 |
|
83.54 |
|
87.8 |
|
2 |
|
0.82 |
|
2024 |
|
3.7 |
|
3.23 |
|
75 |
|
86.06 |
|
90.3 |
|
2 |
|
0.825 |
|
2025 |
|
3.77 |
|
3.34 |
|
77.5 |
|
89.09 |
|
93.33 |
|
2 |
|
0.825 |
|
2026 |
|
3.85 |
|
3.41 |
|
80.41 |
|
92.62 |
|
96.86 |
|
2 |
|
0.825 |
|
2027 |
|
3.93 |
|
3.48 |
|
82.02 |
|
94.57 |
|
98.81 |
|
2 |
|
0.825 |
|
2028 |
|
4 |
|
3.54 |
|
83.66 |
|
96.56 |
|
100.8 |
|
2 |
|
0.825 |
| 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 |
1,611,942 |
|
111,793 |
|
601,968 |
|
462,720 |
|
22,518 |
|
412,943 |
|
- |
|
412,943 |
|
Proved Plus Probable Reserves |
3,890,561 |
|
324,825 |
|
1,379,871 |
|
859,026 |
|
38,729 |
|
1,288,109 |
|
196,543 |
|
1,091,566 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
$/MMcf |
|
Proved Reserves |
|
Light and Medium Oil
(1) |
|
37,336 |
|
14.64 |
|
2.44 |
|
|
|
Tight
Oil (1) |
|
7 |
|
15.83 |
|
2.64 |
|
|
|
Conventional Natural Gas (2) |
|
11,041 |
|
4.17 |
|
0.70 |
|
|
|
Shale
Natural Gas |
|
129,426 |
|
2.94 |
|
0.49 |
|
|
|
Total |
|
177,810 |
|
3.62 |
|
0.60 |
|
Proved Plus Probable Reserves |
|
Light
and Medium Oil (1) |
|
70,019 |
|
15.23 |
|
2.54 |
|
|
|
Tight
Oil (1) |
|
12 |
|
17.91 |
|
2.98 |
|
|
|
Conventional Natural Gas (2) |
|
28,028 |
|
2.45 |
|
0.41 |
|
|
|
Shale
Natural Gas |
|
346,896 |
|
3.71 |
|
0.62 |
|
|
|
Total |
|
444,955 |
|
4.06 |
|
0.68 |
|
|
|
|
|
|
|
|
|
|
Notes:
- Includes solution gas and other
by-products
- Including by-products but excluding
solution gas
- Other Company revenue and costs not
related to a specific production group have been allocated
proportionately to production groups. Unit values are based
on Company Net Reserves.
Dunvegan Oil: Company Interest Reserves
Reconciliation
| |
|
|
Proved
Producing |
|
|
Total Proved |
|
|
Total Proved Plus
Probable |
|
|
|
|
|
|
|
|
|
|
|
|
Technical Revisions |
|
|
85.7 |
|
|
72.9 |
|
|
246.1 |
|
Drilling Extensions |
|
|
1,493.1 |
|
|
1,378.6 |
|
|
2,493.5 |
|
Change in Finding and Development Costs ($M) |
|
$ |
0 |
|
$ |
10,192 |
|
$ |
20,890 |
| 2018
Capital |
|
$ |
19,961 |
|
$ |
19,961 |
|
$ |
19,961 |
|
F&D ($/boe)(1) |
|
$ |
12.64 |
|
$ |
20.77 |
|
$ |
14.91 |
| 2018
Netback ($/boe) (1) |
|
$ |
34.74 |
|
$ |
34.74 |
|
$ |
34.74 |
|
Recycle Ratio(1) |
|
|
2.7 |
|
|
1.7 |
|
|
2.3 |
|
|
|
|
|
|
|
|
|
|
|
Notes:
- See “Non-GAAP Measures” in this press
release.
Board of Directors and Management
Update
Daryl Gilbert has announced his resignation from
the Company’s board, effective the end of the day today, March 12,
2019. Mr. Gilbert has served on the Company’s board since 2012, and
Cequence and the rest of the board thank Mr. Gilbert for his years
of dedicated service to the Company and his contribution to helping
the Company navigate a difficult commodity price environment.
Cequence is pleased to announce that Dan O’Neil
has been appointed to the Company’s board effective today. Mr.
O’Neil is a professional engineer with over 30 years of experience
in the Canadian oil and gas business, including senior management
positions with EnCana Corporation and later serving as the Chief
Executive Officer of Surge Energy Inc. until May 2013. Mr. O’Neil
was also one of the founders of Breaker Energy Ltd., which was
acquired by NAL Energy Corporation (formerly NAL Oil & Gas
Trust)
As previously announced on February 12, 2019
Allan Mowbray will be joining Cequence as Chief Financial Officer
effective March 15, 2019. In connection Mr. Mowbray joining the
Company, Howard Crone has, effective today, resigned from his
position as Executive Vice President of the Company. Mr. Crone will
continue to serve as a director of Cequence. Also effective today,
Donald Archibald’s title will change from Executive Chairman to
Chairman.
2019 Guidance:
The Company’s guidance for the year ended
December 31, 2019 includes the results of the fourth quarter 2018
oil wells, the restructured $60 million Term Loan (with its 5%
interest rate), and an additional planned 2 gross (2 net) Dunvegan
oil wells drilled and on production at the end of the third quarter
of 2019. Cequence will continue to monitor volatility in commodity
prices with the focus that 2019 capital activity will remain within
funds flow from operations.
| (000’s,
except per share and per unit references) |
Guidanceyear
endedDecember 31, 2019 |
|
Average production, BOE/d (1) |
5,800 |
| Funds
flow from operations ($)(2) |
17,000 |
| Funds
flow from operations per share(2) |
0.69 |
|
Exploration and development expenditures ($) |
13,000 |
| Net
wells |
2.0 |
|
Operating and transportation costs ($/boe) |
15.00 |
|
G&A costs ($/boe) |
2.30 |
|
Royalties (% revenue) |
10 |
| Crude
– WTI (US$/bbl) |
57.50 |
|
Natural gas – AECO (CDN$/GJ) |
1.69 |
|
Period end, net debt ($) (3) |
69,000 |
|
Common shares outstanding end of period |
24,553 |
|
|
|
(1) Average production estimates on a per BOE
basis are comprised of 72% natural gas and 28% oil and natural gas
liquids in 2019.(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. See “Non-GAAP Measures” in this press
release.(3) Net debt is calculated as working capital deficiency
(excluding commodity contracts) plus the aggregate principal amount
of the term loan.
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.
For further information
contact:
Todd Brown, Chief Executive Officer, (403)
806-4049, tbrown@cequence-energy.comAllan Mowbray, Chief Financial
Officer, (403) 806-4041, amowbray@cequence-energy.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 for the year ended December 31, 2019 and its
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
Non-GAAP Measures
This press release contains references to terms
and financial measures commonly used in the oil and gas industry
but that do not have a standardized meaning prescribed by
International Financial Reporting Standards (“IFRS”) in Canada and
are therefore unlikely to be comparable to similar measures
presented by other companies. Such terms and financial measures are
referred to as “Non-GAAP Measures”. The Non-GAAP Measures used in
this press release are described below. Non-GAAP Measures should
not be used to make comparisons between companies, including
Cequence.
Total revenue is a Non-GAAP Measure 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 Measure
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 are Non-GAAP
Measures. 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.
Net debt is a Non-GAAP Measure that is
calculated as working capital deficiency (excluding commodity
contracts) plus the principal value of the Term Loan (previously
the Senior Notes) which reflects the estimated amount that will be
repaid upon maturity. Cequence uses net debt as it provides an
estimate of the Company’s assets and obligations expected to be
settled in cash.
Finding and Development (“F&D”) costs and
Finding, Development and Acquisition (“FD&A”) costs . have been
calculated in accordance with NI 51-101. F&D costs are
calculated by dividing the sum of the total capital expenditures
for the year (in dollars) by the change in reserves within the
applicable reserves category (in boe). F&D costs includes all
current year net capital expenditures, excluding property
acquisitions and dispositions with associated reserves, including
changes in future development capital (“FDC”) on a proved or proved
plus probable basis. FD&A costs are calculated by dividing the
sum of the total capital expenditures for the year including both
costs and associated reserve additions related to acquisitions net
of any dispositions during the year, by the change in reserves
within the applicable reserves category. 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 and FD&A costs as a measure to assess the
performance of the Company's resources required to locate and
extract new hydrocarbon reservoirs, including the effect of
acquisitions and dispositions. 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. F&D and FD&A
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.
Oil & Gas Disclosure Advisories
This press 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 2018 the ratio between the average
price of West Texas Intermediate (“WTI”) crude oil at Cushing and
NYMEX natural gas was approximately 20:1 (“Value Ratio”). The Value
Ratio is obtained using the 2018 WTI average price of $65.20
(US$/Bbl) for crude oil and the 2018 NYMEX average price of $3.20
(US$/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.