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 $0.08/share;
- Improved egress with firm service contracted for all of the Company’s Simonette natural gas production;
- Added market diversity away from AECO with 10,850 GJ/d of production to be sold at Dawn beginning April 1, 2018; and
- Drilled, completed, and tied in 3 gross (2 net) Dunvegan oil wells this winter with production to commence the middle of March, 2018.
Comparative financial and operating information for 2017 and 2016 are as follows:
Three months ended |
Twelve months ended |
||||||
(000’s except per share and per unit amounts) |
|||||||
2017 |
2016 |
% Change |
2017 |
2016 |
% Change |
||
FINANCIAL |
|||||||
Total revenue(1) |
13,585 |
17,253 |
(21) |
65,836 |
59,074 |
11 |
|
Comprehensive loss |
(6,638) |
(9,077) |
(27) |
(99,362) |
(28,057) |
(254) |
|
Per share – basic and diluted |
(0.03) |
(0.04) |
(25) |
(0.40) |
(0.13) |
(208) |
|
Funds flow from operations (2)(5) |
1,583 |
6,625 |
(76) |
19,329 |
11,250 |
72 |
|
Per share, basic and diluted |
0.01 |
0.03 |
(67) |
0.08 |
0.05 |
60 |
|
Capital expenditures, before acquisitions (dispositions) |
5,593 |
11,460 |
(51) |
25,857 |
22,590 |
14 |
|
Capital expenditures, including acquisitions (dispositions) |
1,316 |
11,406 |
(88) |
21,580 |
17,296 |
25 |
|
Net debt (3) |
(68,501) |
(64,031) |
7 |
(68,501) |
(64,031) |
7 |
|
Weighted average shares outstanding – basic & diluted |
245,528 |
235,028 |
4 |
245,528 |
217,061 |
13 |
|
OPERATING |
|||||||
Production volumes |
|||||||
Natural gas (Mcf/d) |
33,331 |
45,005 |
(26) |
40,466 |
45,442 |
(11) |
|
Crude oil (bbls/d) |
283 |
140 |
102 |
344 |
177 |
94 |
|
Natural gas liquids (bbls/d) |
257 |
209 |
23 |
254 |
237 |
7 |
|
Condensate (bbls/d) |
617 |
760 |
(19) |
797 |
841 |
(5) |
|
Total (boe/d) |
6,713 |
8,609 |
(22) |
8,139 |
8,826 |
(8) |
|
Sales prices |
|||||||
Natural gas, including realized hedges ($/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 |
Tight Oil |
Conventional |
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 |
255 |
211 |
0 |
0 |
31,416 |
28,818 |
41,358 |
35,574 |
1,734 |
1,190 |
14,118 |
12,133 |
||||||||||||
Developed Non- |
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 |
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 |
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 |
Royalties |
Operating |
Development |
Abandonment |
Future Net |
Income |
Future Net |
||||||||
Proved |
1,888,733 |
133,308 |
647,023 |
489,366 |
31,457 |
587,580 |
– |
587,580 |
|||||||
Proved Plus |
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 |
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 |
Light and Medium Oil (1) |
37,401 |
12.93 |
2.15 |
||||
Conventional Natural |
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.