Cequence Energy announces third quarter financial and operating results
CALGARY, Nov. 12, 2015 /CNW/ - Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is pleased to announce its operating and financial results for the third quarter of 2015. 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.
Third Quarter 2015 Highlights
- During the third quarter Cequence completed its most recent Dunvegan oil well at Simonette. Initial results from the 7-11-62-26 W5M Dunvegan oil well (50% WI) have exceeded management's expectations, with production over its first 85 operating days of approximately 28,700 bbl or 338 bbls/d of oil and 504 boepd including natural gas and associated NGLs.
- The cost to construct the Simonette shallow cut refrigeration system (50% WI) and sales connection to TransCanada's NGTL system is currently trending approximately $4.5 million below budget (11%) and is expected to be completed ahead of schedule. The 13-11 facility will be taken down for 2 separate one week outages in November to conduct mechanical and electrical tie-ins. The 13-11 refrigeration plant is expected to be commissioned in early 2016.
- Production for the quarter averaged 8,822 boepd as the Company shut-in an average of 2,745 boepd in the quarter directly and indirectly associated with CREC prices and NGTL outages. Ongoing NGTL maintenance outages have resulted in sustained downward pressure on Alliance CREC differential to AECO.
- On August 7, 2015, Cequence was informed of a shut down on the Alliance System that suspended deliveries until August 13th. A total of 475 boepd in the quarter was shut-in as a result of the Alliance outage.
- The Company has reduced net 2015 capital expenditures to $22 million in an effort to preserve balance sheet flexibility. As at September 30, 2015, the Company has net debt of $52.5 million comprised of positive working capital of $7.5 million and $60 million of senior notes which mature in October 2018.
- The Company initiated a strategic review process on October 14, 2015 with a view of maximizing shareholder value.
Paul Wanklyn, President and CEO said, "The Company's recent success in the prolific Dunvegan oil prospect at Simonette has positioned us to materially change our gas/liquids production mix over time. With an undrawn bank line of credit, and focused capital spending aimed at adding shareholder value, we are focused on maintaining our balance sheet strength. Our midstream partnership and the completion of our gas plant in January will satisfy our future infrastructure requirements. Cequence is well positioned to weather the current storm in the energy business and we have initiated a strategic alternatives process in order to make sure all options to maximize shareholder value are examined".
| (000's except per share and per unit amounts) |
Three months ended |
Nine months ended |
|||||||
| 2015 |
2014 |
% Change |
2015 |
2014 |
% Change |
||||
| FINANCIAL |
|||||||||
| Production revenue (1) |
19,383 |
29,013 |
(33) |
64,779 |
111,327 |
(42) |
|||
| Comprehensive income (loss) |
(99,070) |
74,402 |
(233) |
(103,487) |
83,790 |
(224) |
|||
| Per share – basic |
(0.47) |
0.35 |
(234) |
(0.49) |
0.40 |
(223) |
|||
| Per share - diluted |
(0.47) |
0.35 |
(234) |
(0.49) |
0.39 |
(226) |
|||
| Funds flow from operations (2) |
5,139 |
13,588 |
(62) |
20,704 |
56,905 |
(64) |
|||
| Per share, basic |
0.02 |
0.06 |
(67) |
0.10 |
0.27 |
(63) |
|||
| Per share, diluted |
0.02 |
0.06 |
(67) |
0.10 |
0.26 |
(62) |
|||
| Capital expenditures, before acquisitions (dispositions) |
4,656 |
49,239 |
(91) |
47,086 |
123,743 |
(62) |
|||
| Capital expenditures, including acquisitions (dispositions) |
5,792 |
(92,795) |
106 |
2,208 |
(24,658) |
109 |
|||
| Net debt and working capital deficiency (3) |
(52,492) |
(29,911) |
75 |
(52,492) |
(29,911) |
75 |
|||
| Weighted average shares outstanding – basic |
211,028 |
211,028 |
- |
211,028 |
210,978 |
- |
|||
| Weighted average shares outstanding - diluted |
211,028 |
214,569 |
(2) |
211,028 |
215,339 |
(2) |
|||
| OPERATING |
|||||||||
| Production volumes |
|||||||||
| Natural gas (Mcf/d) |
43,987 |
49,515 |
(11) |
49,541 |
58,036 |
(15) |
|||
| Crude oil (bbls/d) |
199 |
118 |
69 |
138 |
125 |
10 |
|||
| Natural gas liquids (bbls/d) |
485 |
523 |
(7) |
534 |
598 |
(11) |
|||
| Condensate (bbls/d) |
807 |
801 |
1 |
984 |
945 |
4 |
|||
| Total (boe/d) |
8,822 |
9,694 |
(9) |
9,913 |
11,340 |
(13) |
|||
| Sales prices |
|||||||||
| Natural gas, including realized hedges ($/Mcf) |
3.46 |
4.19 |
(17) |
3.38 |
4.71 |
(28) |
|||
| Crude oil ($/bbl) |
47.01 |
90.77 |
(48) |
49.58 |
94.09 |
(47) |
|||
| Natural gas liquids ($/bbl) |
16.80 |
38.34 |
(56) |
17.15 |
44.59 |
(62) |
|||
| Condensate ($/bbl) |
50.83 |
96.02 |
(47) |
54.85 |
101.33 |
(46) |
|||
| Total ($/boe) |
23.88 |
32.53 |
(27) |
23.94 |
35.96 |
(33) |
|||
| Netback ($/boe) |
|||||||||
| Price, including realized hedges |
23.88 |
32.53 |
(27) |
23.94 |
35.96 |
(33) |
|||
| Royalties |
(0.45) |
(4.35) |
(90) |
(1.26) |
(4.17) |
(70) |
|||
| Transportation |
(1.63) |
(1.44) |
13 |
(1.84) |
(1.48) |
24 |
|||
| Operating costs |
(11.03) |
(7.65) |
44 |
(9.13) |
(7.90) |
16 |
|||
| Operating netback |
10.77 |
19.09 |
(44) |
11.71 |
22.41 |
(48) |
|||
| General and administrative |
(2.53) |
(2.12) |
19 |
(2.20) |
(2.20) |
- |
|||
| Interest(4) |
(2.06) |
(1.99) |
4 |
(1.91) |
(1.87) |
2 |
|||
| Cash netback |
6.18 |
14.98 |
(59) |
7.60 |
18.34 |
(59) |
|||
| (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 share based payment liabilities and provisions. |
|
| (4) |
Represents finance costs less amortization on transaction costs and accretion expense on senior notes and provisions. |
Production and Facilities
Production averaged 8,822 boepd in the third quarter, a decrease of 9 percent from the second quarter. Cequence continues to reduce its exposure to high CREC price differentials by restricting its natural gas production to its contracted volumes of 40,000 GJ/d. Any of the Company's production above the contracted volumes would be priced at AECO less the CREC differential which would have resulted in Cequence receiving a negative realized gas price in the third quarter. Cequence estimates that production curtailments and NGTL related shut-ins impacted quarterly average production volumes by 2,745 boepd. In addition, an Alliance Pipeline Force Majeure event announced on August 7th resulted in 475 boepd of shut in production for the quarter. The corporate production capability for the third quarter was approximately 12,000 boepd with the combined shut-in and curtailed volumes of 3,220 boepd.
The shallow cut refrigeration addition (120 MMcfd) at the 13-11-62-27W5M facility (50% WI) is currently progressing ahead of schedule and approximately 11% under budget resulting in gross savings of $4.5 million. Given the accelerated progress, Cequence has elected to schedule two separate field-wide shut-ins spanning two separate weeks in November to conduct mechanical and electrical tie-ins for the new equipment. The shut-ins will affect all wells producing to 13-11 including the Dunvegan oil wells. The plant is expected to be fully operational in February 2016 with the pipeline connection to NGTL expected to be completed in April 2016 at which time Cequence will be connected to both the Alliance and TransCanada pipeline systems.
Cequence has firm gas delivery contracts commencing in December 2015 to market natural gas through the Alliance system at Simonette. This 11 month contract starts at 40,000 GJ/day for the first 4 months and reduces to 20,000 GJ/day for the next 7 months and is staged to coincide with the startup of the NGTL meter station and access to that system. In addition, the Company expects major third party pipeline maintenance to be completed by December 2015 and for CREC differentials to normalize. Cequence intends to increase its natural gas production volumes should this occur.
Dunvegan Oil Project
The initial 7-11-62-26W5 (50% WI) oil well was completed over a 2,000 m lateral using 31 stages in July. Including the flow test, the well has produced a total of approximately 28,700 bbls of 41 degree API oil over 85 operating days (338 bbls/day), with a September average rate of 308 bbls/d. On October 23rd, 2015 modifications to the surface facility were completed which allowed the well to increase production to approximately 366 bbls/d oil for the last 7 days of October.
Cequence recently drilled a step out well at 4-11 (50% WI) to a measured depth of 5,545 m and 3,030 m of lateral section. A total of 56 frac sleeves were run in the well and the completion will commence later in November.
A third well is planned (100% WI) to be spud west of the first two locations in December, with a fourth well (50% WI) scheduled for early January.
Based on existing well control and 3D seismic mapping, Cequence believes that it has identified approximately 9 gross (7.5 net) sections adjacent to the 7-11 well that have potential for Dunvegan oil development.
Montney Update
Cequence Montney wells are performing as expected with most shut-in production expected to return to full capability once CREC prices correct in December, 2015. Cequence is currently moving a rig to spud a planned 3,000 meter lateral well at 16-33-61-27W5. The completion will deploy 75 stage slickwater fracs using a sliding sleeve annular coil system and is expected to be finished prior to year-end. This well will be the longest lateral Montney well Cequence has drilled in the Simonette area with higher completion intensity than the recent 26 stage ball & seat systems. The 16-33 well is expected to be drilled and completed for 10% lower cost than the 2014 Cequence average despite being 36% longer and with 2.8 times the number of frac stages.
FINANCIAL
Funds flow from operations decreased to $5.1 million in the third quarter of 2015 compared to $13.6 million for 2014. The decrease in funds flow from operations is due largely to lower oil and natural gas prices and lower production volumes in 2015. Realized sales prices (including hedging) decreased 27 percent from the comparative period as benchmark AECO natural gas prices averaged $2.91/mcf for the third quarter. Comprehensive loss for the quarter ended September 30, 2015 was $99.1 million as Cequence recorded an impairment loss due to ongoing low crude oil and natural gas prices.
Capital expenditures were $5.8 million in the third quarter and related primarily to the refrigeration expansion at the Company's 13-11 facility at Simonette and the completion and equipping of the 7-11-62-26W5M Dunvegan oil well. As a result, the Company exited the third quarter with net debt of $52.5 million. Net debt is comprised of $60 million in senior notes carrying a five year term and positive working capital of $7.5 million.
Cequence has hedged approximately 68 percent of its estimated fourth quarter natural gas production (net of royalties) at an average price of $3.40/GJ or $4.00/mcf based on the historical heat content of the Company's natural gas. The Company intends to continue to actively hedge production with a view towards protecting the balance sheet and future capital spending programs.
Outlook and Revised Guidance
The winter drilling program has been designed to add value for shareholders while maintaining the strength of our balance sheet. The early results of the Dunvegan light oil play are encouraging and management believes that the economics of this capital program are supported in the current commodity price environment. The winter program will continue to delineate the Dunvegan play with three additional wells planned to evaluate the future development potential of the Company's lands. The initial success achieved in the Dunvegan formation with longer reach horizontal wells using sliding sleeves and annular fracs will be also be applied to the Montney well planned for the fourth quarter of 2015.
Planned capital expenditures for 2015 have been reduced to $22 million, net of dispositions. Remaining capital expenditures are forecast to be focused on the Simonette refrigeration plant construction and the drilling of 3 (2.5 net) wells at Simonette described above. Funds flow is expected to be $26 million, reflecting lower production volumes and higher operating costs than previously forecasted.
Operating costs per boe have increased primarily due to both lower forecast production volumes and one-time expenses. For the nine months ended September 30, 2015 operating costs have increased by $2.1 million (9%) and the third quarter costs increased by $1 million (12.8%) associated with one time third party plant turnarounds, and in-field short term rental charges. Excluding these one-time charges, unit expenses decrease by $0.78 /boe and $1.32/boe respectively. Production volumes in the third quarter were curtailed by approximately 27%. With volumes on, Cequence estimates the operating costs would have been under $9.00/boe for the quarter. Beginning in October, Cequence has begun to reduce the in-field rental charges with an expectation of minimizing this expense in 2016. It is anticipated near full resumption of volumes will occur through December, 2015.
Due to higher than anticipated production curtailments and additional downtime associated with the plant construction, Cequence is reducing its estimate for 2015 average production to 9,500 boe/d. The Company has 40,000 GJ/d contracted on Alliance for December-March 2015 and anticipates increasing production volumes above 40,000 GJ/d if CREC differentials improve.
The Company plans to exit 2015 with approximately $68 million in net debt, leaving the Company with ample liquidity on its undrawn credit facility of which $60 million will remain on its senior notes and $8.0 million of bank debt and working capital. The senior notes have a term until October 2018.
| (000s other than per share amounts) |
August 13, 2015 |
Revised 2015 |
|
| Average production, BOE/d (1) |
10,200 |
9,500 |
|
| Funds flow from operations ($)(2) |
30,000 |
26,000 |
|
| Funds flow from operations per share(2) |
$0.14 |
$0.12 |
|
| Capital expenditures, prior to dispositions ($) |
69,000 |
67,000 |
|
| Capital expenditures, net of dispositions ($) |
23,000 |
22,000 |
|
| Operating and transportation costs ($ per boe) |
10.20 |
11.20 |
|
| G&A costs ($ per boe) |
2.50 |
2.35 |
|
| Royalties (% revenue) |
8 |
6-8 |
|
| Crude – WTI (US$/bbl) |
51.00 |
51.00 |
|
| Natural gas – AECO (Cdn$/GJ) |
2.70 |
2.60 |
|
| Period end, net debt and working capital deficiency ($) (3) |
65,000 |
68,000(4) |
|
| Basic shares outstanding |
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 share based payment liability and provisions. |
| (4) |
Comprised of $60 million in senior notes and $8.0 million in working capital and bank debt. |
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: business strategy and objectives; the Company's 2015 capital program; the effect of shut-ins on production and cash flow; the Company's plans to actively hedge to protect future capital spending programs; funds flow; net debt; future production levels; drilling plans; techniques and processes and the associated benefits to be derived therefrom; well and tie-in completions, including the anticipated benefits resulting therefrom; facility construction and commissioning and timing for completion thereof; expected future oil and gas prices and CREC differentials. 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.
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 nine months ended September 30, 2015, 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 first nine months of 2015 WTI average price of $50.94 (US$/Bbl) for crude oil and the first nine months 2015 NYMEX average price of $2.56 (US$/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.
Paul Wanklyn, Chief Executive Officer, (403) 218-8850, [email protected]; David Gillis, Chief Financial Officer, (403) 806-4041, [email protected]
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