CALGARY, March 6, 2014 /CNW/ – Cequence Energy Ltd. (“Cequence” or the “Company”) (TSX: CQE) is pleased to announce its 2013 operating and financial results for the three months and the year ended December 31, 2013. The Company’s Audited Consolidated Financial Statements and Management’s Discussion and Analysis for the years ended December 31, 2013 and 2012 are available at cequence-energy.com and on SEDAR at www.sedar.com.
Highlights
Financial highlights for 2013 include:
- Increased annual funds flow by 52 percent to $51.3 million or $0.25 per share;
- Increased fourth quarter funds flow by 28 percent to $14.9 million or $0.07 per share;
- Maintained a top quartile cost structure with cash costs of $12.14 per boe;
- Increased the annual operating netback by 40 percent to $16.84; and
- Strengthened the balance sheet with the issuance of 5 year term notes with CPPIB.
Operational highlights for 2013 include:
- Increased annual average production by 13 percent over prior year to 10,183 boepd and fourth quarter production by 16 percent to 10,394 boepd;
- Efficiently added reserves with proved plus probable FD&A costs of $11.17 and F&D costs of $10.10;
- Increased in proved plus probable reserves by 24 percent to 133 mmboe;
- Established a new core area at Ansell with successful Wilrich results and accelerated development through a farm out arrangement;
- Consolidated the minority working interests in the Simonette Montney assets with a property acquisition in April 2013 with the Simonette Montney now with 74 mmboe of proved plus probable reserves with an NPV 10% of $687 million.
“2013 was an excellent year for Cequence highlighted by continued success at Simonette and the establishment of a new core area at Ansell” said Paul Wanklyn, President and CEO. “Our team successfully added to our land positions at Simonette and Ansell while achieving low FD&A costs of $11.17, growing production by 13 percent and cash flow by 52 percent. In 2014, we plan to build on this momentum by delivering material production growth and executing on our five year plan.”
| Financial and Operating Highlights | |||||||||||||
| (000’s except per share and per unit amounts) |
Three months ended December 31, |
Twelve months ended December 31, |
|||||||||||
| 2013 | 2012 | % Change |
2013 | 2012 | % Change |
||||||||
| Financial ($) | |||||||||||||
| Production revenue (1) | 28,483 | 21,939 | 30 | 105,617 | 75,650 | 40 | |||||||
| Comprehensive income (loss) | (827) | 666 | (224) | (2,613) | (17,673) | (85) | |||||||
| Per share, basic and diluted | (0.00) | (0.00) | – | (0.01) | (0.10) | (90) | |||||||
| Funds flow from operations, excluding termination fee (2) | 14,855 | 11,564 | 28 | 51,312 | 30,377 | 69 | |||||||
| Funds flow from operations (2) | 14,855 | 11,603 | 28 | 51,312 | 33,724 | 52 | |||||||
| Per share, basic and diluted | 0.07 | 0.06 | 17 | 0.25 | 0.19 | 32 | |||||||
| Production volumes | |||||||||||||
| Natural gas (Mcf/d) | 53,433 | 47,125 | 13 | 52,705 | 47,137 | 12 | |||||||
| Crude oil (bbls/d) | 838 | 583 | 44 | 792 | 622 | 27 | |||||||
| Natural gas liquids (bbls/d) | 651 | 515 | 26 | 607 | 512 | 19 | |||||||
| Total (boe/d) | 10,394 | 8,951 | 16 | 10,183 | 8,990 | 13 | |||||||
| Sales prices | |||||||||||||
| Natural gas, including realized hedges ($/Mcf) | 3.82 | 3.49 | 9 | 3.57 | 2.67 | 34 | |||||||
| Crude oil ($/bbl) | 87.37 | 86.78 | 1 | 91.81 | 85.02 | 8 | |||||||
| Natural gas liquids ($/bbl) | 49.54 | 45.83 | 8 | 46.63 | 54.76 | (15) | |||||||
| Total ($/boe) | 29.79 | 26.64 | 12 | 28.42 | 22.99 | 24 | |||||||
| Netback ($/boe) | |||||||||||||
| Price | 29.79 | 26.64 | 12 | 28.42 | 22.99 | 24 | |||||||
| Royalties | (1.85) | (1.88) | (1) | (2.32) | (1.45) | 60 | |||||||
| Transportation | (1.62) | (1.76) | (8) | (1.60) | (2.04) | (22) | |||||||
| Operating costs | (7.33) | (6.55) | 12 | (7.66) | (7.43) | 3 | |||||||
| Operating netback | 18.99 | 16.45 | 15 | 16.84 | 12.07 | 40 | |||||||
| General and administrative | (1.65) | (1.85) | (11) | (1.95) | (2.16) | (10) | |||||||
| Interest(5) | (1.77) | (0.49) | 261 | (0.93) | (0.61) | 52 | |||||||
| Cash netback | 15.57 | 14.11 | 10 | 13.96 | 9.30 | 50 | |||||||
| Capital Expenditures ($) | |||||||||||||
| Capital expenditures | 51,578 | 23,997 | 115 | 117,909 | 91,658 | 29 | |||||||
| Net acquisitions (dispositions) (4) | (47) | 644 | (107) | (2,675) | (13,258) | (80) | |||||||
| Total capital expenditures | 51,531 | 24,641 | 109 | 115,234 | 78,400 | 47 | |||||||
| Net debt and working capital (deficiency) (3) | (111,433) | (45,869) | 143 | (111,433) | (45,869) | 143 | |||||||
| Weighted average shares outstanding | |||||||||||||
| Basic and diluted | 210,917 | 194,224 | 9 | 207,950 | 178,209 | 17 | |||||||
| Notes: | |
| (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. For the three and twelve months ended December 31, 2012, funds flow from operations included a $39 and $3,347 termination fee (net of transaction costs) related to an unsuccessful acquisition. |
| (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
Canadian natural gas prices averaged $3.17 per mcf in 2013, an increase of 33 per cent from 2012 when AECO natural gas prices averaged $2.38 per mcf representing the lowest average annual price since 1998. AECO prices recovered in 2013 as inventory levels decreased in response to a colder North American winter and slowing growth in natural gas production. For the year ended December 31, 2013, Cequence realized gas price increases of 34 percent to $3.57 contributing to an increase to the operating netback for the year ended December 31, 2013 of 40 percent to $16.84. Cequence operating costs increased three percent from prior year to $7.66 per boe and remain within the top quartile of natural gas producers in Canada.
Funds flow from operations increased to $51.3 million for twelve months ended December 31, 2013 compared to $33.7 million for the twelve months ended December 31, 2012. The increase in funds flow from operations is due largely to a 40 percent increase in revenue resulting from higher realized oil and natural gas prices and a 13 percent increase in production volumes. Funds flow from operations was $14.9 million for the three months ended December 31, 2013, compared to $11.6 million for the three months ended December 31, 2012. Cequence was able to increase funds flow from operations as a result of increased commodity prices and 16 percent higher production than in the prior year.
Comprehensive net loss for the year ended December 31, 2013 was $2.6 million compared to $17.7 million in 2012. The reduction in the annual loss is a result of higher operating netbacks in 2013. Cequence recorded a comprehensive loss of $0.8 million for the fourth quarter of 2012 compared to comprehensive income of $0.6 million in the same period in 2012. The loss in the fourth quarter of 2013 is a result of increased finance costs of $1.4 million and an unrealized hedging loss of $3.8 million that offset an increase in operating cash flow.
Capital expenditures, prior to assets acquired or disposed of for non-cash consideration, were $51.5 in the fourth quarter of 2013 and $115.2 million for the year ended December 31, 2013. For the year ended December 31, 2013, Cequence participated in drilling 15 (11.75 net) wells including 9.0 (9.0 net) Montney wells, 4.0 (1.45 net) Wilrich wells, 1.0 (0.65) Falher wells and 1.0 (0.65) Dunvegan wells. Equipment and facility expenditures for the year ended December 31, 2013 of $27.1 million were mainly directed towards an expansion of the Simonette compression and dehydration facility along with additional pipeline and gathering systems.
In addition, Cequence acquired 19.2 net sections of Montney land at Simonette in 2013 for share consideration of $17.5 million and non-core oil and gas properties with a fair value of $6.0 million. The acquisition closed in April 2013 and resulted in the consolidation of the Company’s contiguous Montney land at Simonette.
The Company exited 2013 with available credit facilities of $180 million versus net debt of $111.4 million. Net debt is comprised of $60 million in senior notes carrying a five year term, bank debt of $22.7 million and a working capital deficiency of $28.7 million.
Operations Update
Cequence recently publicly announced its drilling results at Ansell. Initial test rates on its two recent wells are positive and facility work is ongoing to increase production capacity in the area. The Company expects to have 7.0 gross (3.5 net) Wilrich wells at Ansell completed prior to the end of the first quarter. On completion of the facility expansion these wells are expected to be on production in May 2014.
Completion of the Montney step-out well at 16-10 is underway and initial results are expected in the coming weeks. In addition, the Company expects to complete its final Montney well of the winter at 13-35-61-57W5 prior to spring break-up.
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; 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; 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, however, 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.
Finding, Development and Acquisition Costs (“FD&A”) and Finding and Development Costs (“F&D”) have been calculated in accordance with NI 51-101. Finding and development costs refers to all current year net capital expenditures, excluding property acquisitions and dispositions with associated reserves, and including changes in future development capital 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 in F&D and FD&A costs is available in the Company’s Annual Information Form filed on SEDAR. Management uses finding and development costs as a measure to assess the performance of the Company’s resources required to locate and extract new hydrocarbon reservoirs.
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 2013, the ratio between the average price of West Texas Intermediate (“WTI”) crude oil at Cushing and NYMEX natural gas was approximately 26:1 (“Value Ratio”). The Value Ratio is obtained using the 2013 WTI average price of $98.01 (US$/Bbl) for crude oil and the 2013 NYMEX average price of $3.73 (US$/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. {NTD: These are different from your February press release, confirm these are the correct numbers)
The TSX has neither approved nor disapproved the contents of this news release.
SOURCE Cequence Energy Ltd.
For further information:
Paul Wanklyn, Chief Executive Officer, (403) 218-8850, pwanklyn@cequence-energy.com
David Gillis, Chief Financial Officer, (403) 806-4041, dgillis@cequence-energy.com