Cequence Energy announces 35% growth in reserves and 2012 financial and operating results

CALGARY, March 7, 2013 /CNW/ - Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: "CQE") is pleased to announce its 2012 year end reserves and its operating and financial results for the three months and the year ended December 31, 2012.

Reserve Highlights

Cequence's 2012 year end reserves reflect a continued focus on the successful delineation of its Simonette property in the Deep Basin of Alberta.  The growth in reserves further substantiates management's views that the Company's assets contain significant resource potential.  The following highlights are based on the reserve report dated March 5, 2013 and effective December 31, 2012 (the "GLJ Report") prepared by GLJ Petroleum Consultants ("GLJ"):

  • Increased proved reserves by 32% from the prior year to 46 MMBOE;
  • Increased proved plus probable reserves by 35% from the prior year to 91 MMBOE;
  • Increased total proved plus probable reserves at Simonette by 55% from the prior year to 77 MMBOE;
  • Achieved finding, development and acquisition costs (including changes to future development capital) of $10.57 per boe on a proved plus probable basis and $12.93 per boe on a proved basis;
  • Increased the net present value of the Company's proved plus probable reserves by 12% from the prior year to $797 million or $3.97 per share (using a discount rate of 10%); and
  • Replaced 820% of production with proven plus probable reserves.

Financial and Operating Highlights

Cequence has focused its efforts on expanding its asset value and resource base through the continued delineation of the extensive Montney formation and the exploration for additional reservoir targets at Simonette.  Significant financial and operating highlights are as follows:

  • Reduced annual operating costs by 18% from the prior year to $7.43 per boe and decreased fourth quarter operating costs by 24% from the fourth quarter of 2011 to $6.55 per boe;
  • Reduced fourth quarter cash costs by 18% from prior year to $10.65 per boe;
  • Maintained a strong balance sheet with year end debt of $45.9 million resulting in a debt to annualized fourth quarter cash flow ratio of 1:1;
  • Increased fourth quarter funds flow from operations by 16%  to $11.6 million or $0.06 per share, from the fourth quarter of 2011;
  • Increased fourth quarter operating netback by 13% from prior year to $16.45, despite an 8 percent decrease in commodity prices;
  • Drilled key land retention/delineation wells for the Montney formation at Simonette while lowering drilling costs and increasing horizontal target length;
  • Discovered new resource potential at Simonette with exploration success in the Falher and Dunvegan formations;
  • Completed the Aux Sable tie-in and meter station in June 2012 resulting in improved liquids extraction;
  • Drilled and completed a total of 7.0 gross (5.8 net) horizontal wells at Simonette in 2012; and
  • Annual production averaged 8,990 boepd and fourth quarter production averaged 8,951 boepd.


(000's except per share and per unit
  Three months ended
December 31
Year ended
December 31
    2012 2011 Change 2012 2011
Financial ($)              
Production revenue (1)   21,939 23,527 (7) 75,650 101,996 (26)
Comprehensive income (loss)   666 (15,598) 104 (17,673) (20,158) (12)
Per share, basic and diluted   (0) (0.10) 100 (0.10) (0.14) (29)
Funds flow from operations (2)   11,603 10,002 16 33,724 42,262 (20)
Per share, basic and diluted   0.06 0.06 - 0.19 0.29 (34)
Production volumes              
Natural gas (Mcf/d)   47,125 47,203 - 47,137 47,825 (1)
Crude oil (bbls/d)   583 503 16 622 575 8
Natural gas liquids (bbls/d)   515 509 1 512 464 10
Total (boe/d)   8,951 8,879 1 8,990 9,010 -
Sales prices              
Natural gas, including realized hedges ($/Mcf)   3.49 3.59 (3) 2.67 4.03 (34)
Crude oil ($/bbl)   86.78 97.15 (11) 85.02 92.60 (8)
Natural gas liquids ($/bbl)   45.83 73.19 (37) 54.76 71.99 (24)
Total ($/boe)   26.64 28.80 (8) 22.99 31.02 (26)
Operating Netback ($/boe)              
Price   26.64 28.80 (8) 22.99 31.02 (26)
Royalties   (1.88) (3.75) (50) (1.45) (4.18) (65)
Transportation   (1.76) (1.93) (9) (2.04) (2.18) (6)
Operating costs   (6.55) (8.60) (24) (7.43) (9.02) (18)
Operating netback   16.45 14.52 13 12.07 15.64 (22)
Capital Expenditures ($)              
Capital expenditures   23,997 56,335    (57) 131 91,658 149,601 (39)
Net acquisitions (dispositions) (4)   644 - 100 (13,258) (23,023) (42)
Total capital expenditures      24,641 56,335 (56)    78,400    126,578 (38)
Net debt and working capital (deficiency) (3)   (45,869) (51,442) (11) (45,869) (51,442) (11)
Weighted average shares outstanding  (basic and diluted)   194,224 161,818 20 178,209 147,558 21
Undeveloped land (net acres)   204,215  254,400  (20) 204,215  254,400 (20)
Wells drilled  gross (net)   3(2.7) 7(5)   7(5.8) 1  
(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 year ended December 31, 2012, funds flow from operations included a $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 and demand credit facilities 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) Cash costs include operating expense, transportation expense, general and administrative expense and interest expense.


Canadian natural gas prices averaged $2.38 per mcf in 2012, down 35 per cent from $3.64 per mcf in 2011.  Lower natural gas prices were largely attributed to high inventory levels resulting from record high North American production and low heating demand.  Reduced North American natural gas drilling activity, fuel switching and lower Canadian production helped balance inventory levels in late 2012 resulting in higher gas prices in the fourth quarter. Ongoing industry gas drilling activity was directed towards plays with significant natural gas liquids resulting in an oversupply of propane and butane.  The increase in supply caused NGL prices to drop by approximately 25 percent in 2012. This combination of low natural gas and NGL prices has created a difficult macro-environment for natural gas producers.

Funds flow from operations decreased to $33.7 million for twelve months ended December 31, 2012 compared to $42.3 million for the twelve months ended December 31, 2011.  The decrease in funds flow from operations is due largely to a 26 percent decrease in revenue resulting from lower realized oil and natural gas prices.  The reduction in revenue was partially offset by lower royalties, transportation, general and administrative expenses, operating costs and the receipt of a termination fee.

Funds flow from operations was $11.6 million for the three months ended December 31, 2012, compared to $10 million for the three months ended December 31, 2011.  Cequence was able to increase funds flow from operations despite average fourth quarter prices that were 8 percent lower than prior year through decreases in cash costs from the corresponding period in 2011.  Funds flow from operations is a non-GAAP measurement as defined below.

Cequence recorded a comprehensive income of $0.7 million for the fourth quarter of 2012 compared to a comprehensive loss of $15.6 million in the same period in 2011. The fourth quarter of 2011 included an impairment charge of $18.3 million. Comprehensive net loss for the year ended December 31, 2012 was $17.7 million compared to $20.2 million in 2011.  The net loss in both years is partly due to the reserve impairment of non-core properties of $26.9 million in 2012 and $18.3 million in 2011.

Capital expenditures in the fourth quarter of 2012 totalled $24.6 million compared to $56.3 million in the fourth quarter of 2011.  Capital expenditures continue to be focused on drilling, completion and facilities expenditures at Simonette.  Net capital expenditures for the year ended December 31, 2012 were $78.4 million, a decrease of 38 percent from 2011. Cequence adjusted its capital budget throughout 2012 in response to lower natural gas prices.

The Company exited 2012 with net debt of $45.9 million on bank lines totalling $100 million.

The Company's financial statements and management's discussion and analysis for the periods ended December 31, 2012 and the annual information form for the year ended December 31, 2012, which includes information concerning the reserves and other oil and gas information in the form required by National Instrument 51-101 ("NI 51-101"), are available on SEDAR at www.sedar.com.

Outlook and Recent Developments

The 2012 drilling program was designed to further delineate the Montney resource base at Simonette and capture new resource opportunities in the Deep Basin. Successful drilling in 2012, resulted in an additional 23 MMBOE of Montney reserves being booked at Simonette for a total of 55 MMBOE proved plus probable reserves.   Based on an average Montney well from the GLJ reserve report of 4.7 bcf of raw natural gas which includes 99 MBBL of condensate and 42 MBBL of NGLs, development of the Company's Montney assets is economic at today's natural gas prices. The average per well Montney reserves have increased by more than 20 percent from last year's independent reserve report.  Cequence has established a large development inventory at Simonette and approximately 68 horizontal Montney wells are now booked in the Company's year end reserve report.

In 2012, Cequence established two new plays at Simonette with successful wells drilled in the Falher and Dunvegan formations (the latter completed in Q1 2013).  A significant portion of land at Simonette is prospective for the Montney, Falher, Wilrich and Dunvegan Formations, or some combination thereof.  Multizone development is expected to benefit the economics of all of the Company's development drilling through the use of common padsites and gathering facilities.

In February 2013, Cequence announced it had reached an agreement to acquire the Simonette Montney interests of its partner in 33 gross (16.5 net) sections of Montney rights at Simonette and an additional 2.7 net sections at Resthaven.  The transaction is expected to close in mid April 2013.  Cequence believes that the expansion and consolidation of its contiguous Montney land position at Simonette has significant present and future economic and strategic value. Upon closing, Cequence will own approximately 89 net Montney sections at Simonette. Cequence has completed one successful Montney well in the first quarter of 2013 and expects to complete two additional wells prior to spring breakup. A total of 5 wells are expected to be completed in the Falher, Dunvegan and Montney formations during the first quarter of 2013.

In February 2013 Cequence announced a farmout agreement to accelerate the exploration and development of its assets in the Ansell/Edson area of the Deep Basin. Cequence has accumulated 31 sections of land over the past two years targeting an emerging prolific Wilrich play.  Competitor operators have recently experienced excellent success in the Ansell area and preliminary results from the initial Wilrich well into the pool are expected by mid year. Ansell is located in a multi-zone area approximately 85 miles southeast of Simonette.

In 2012, additional measures were taken to improve operating efficiencies in the Simonette field including the completion of the Aux Sable infrastructure project in June 2012.  The Aux Sable project has operated as expected and was a primary driver in reducing corporate operating costs by 24 percent in the fourth quarter from the prior year.  Corporate cash costs in 2012 decreased by 13 percent from 2011 ranking Cequence in the top quartile of gas weighted operators in Canada.

Cequence provided first half 2013 capital budget guidance on February 4, 2013.  Forecast average production of 10,000 boepd in the first half of 2013 represents 11 percent growth from 2012 average production.  Cequence expects that production growth will be weighted exclusively to the second quarter coinciding with the completion of Simonette compression and gathering system expansion.  Cequence is encouraged by the results of its first three wells of 2013 which have tested at a combined aggregate rate of 42 mmcf/d plus liquids.

Paul Wanklyn, President and CEO said, "I am proud of our team's 2012 accomplishments in the face of a challenging environment for natural gas companies.  Our goals were to better define our Simonette Montney resource play within a reduced capital budget, and to expand our opportunity base in new zones both there, and in the Ansell area. We achieved those goals and dramatically increased our reserves with an excellent finding and development cost. We also set out to reduce operating and total cash costs in 2012 and are now one of the lowest cost operators in the Western Canadian Basin.  Cequence invested $25 million in infrastructure at Simonette in 2012 which will benefit the Company in the upcoming years in terms of operating costs and throughput capacity.  We enter 2013 with a strong balance sheet and an expansive inventory of development opportunities. With 50% of our current gas production hedged through 2013 at $3.60 per mcf, we look forward to the continued delineation of our large asset base in a stronger gas price environment."


In accordance with NI 51‐101, GLJ prepared the GLJ Report for the oil, natural gas liquids and natural gas reserves attributable to the properties of Cequence.

The tables below are a summary of the oil, NGL and natural gas reserves attributable to the properties of Cequence and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ Report based on forecast price and cost assumptions. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of Cequence's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Summary of Oil and Gas Reserves

    Light and Medium
Crude Oil
  NGL   Natural Gas    Total Oil Equivalent
Reserves Category   Gross   Net   Gross   Net   Gross   Net   Gross   Net
  (Mbbl)   (Mbbl)   (Mbbl)   (Mbbl)   (MMcf)   (MMcf)   (MBOE)   (MBOE)
  Developed Producing   809   629   863   666   73,622   65,829   13,942   12,266
  Developed Non-Producing   49   39   120   93   6,752   6,001   1,295   1,132
  Undeveloped    2,907   2,088   1,674   1,528   159,440   138,036   31,153   26,622
Total Proved   3,765   2,756   2,657   2,287   239,814   209,867   46,391   40,021
Probable   3,851   2,591   2,516   2,234   229,970   198,125   44,695   37,847
Total Proved plus Probable   7,615   5,347   5,173   4,521   469,783   407,992   91,086   77,867

  (1)  Columns may not add during rounding.
  (2)   "Gross" reserves means the Company's working interest (operated and non‐operated) share before deduction of royalties payable to others and without including any royalty interests of the Company.
  (3) "Net" reserves means the Company's working interest (operated and non‐operated) share after deduction of royalty obligations plus the Company's royalty interests in reserves.

Summary of Net Present Value of Future Net Revenue

Reserves Category   Before Future Income Tax Expenses Discounted at (%/year)
0   5   10   15   20
(M$)   (M$)   (M$)   (M$)   (M$)
  Developed Producing   253,091   205,774   173,947   151,218   134,221
  Developed Non-Producing   14,499   11,282   9,087   7,500   6,305
  Undeveloped    492,388   333,963   237,138   173,469   129,291
Total Proved   759,979   551,019   420,173   332,187   269,817
Probable   917,500   557,549   376,952   271,967   204,624
Total Proved plus Probable   1,677,479   1,108,568   797,124   604,154   474,441

Reserves Category   After Future Income Tax Expenses Discounted at (%/year)
0   5   10   15   20
(M$)   (M$)   (M$)   (M$)   (M$)
  Developed Producing   257,072   209,659   177,743   154,930   137,855
  Developed Non-Producing   14,499   11,282   9,087   7,500   6,305
  Undeveloped    461,605   318,410   228,792   168,760   126,522
Total Proved   733,177   539,350   415,622   331,191   270,682
Probable   689,293   417,292   281,241   202,314   151,746
Total Proved plus Probable   1,422,469   956,643   696,862   533,504   422,427

  (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, 2013 in the GLJ Report in estimating Cequence's reserves data using forecast prices and costs:

Year   Natural Gas   Light Crude Oil   Pentanes Plus   Inflation Rates   Exchange Rate
Henry Hub   AECO Gas Price   WTI Edmonton   Edmonton
($US/MMBtu)   ($Cdn/MMBtu)   ($US/bbl) ($Cdn/bbl)   ($Cdn/bbl)   %/year   ($US/$Cdn)
2013   3.75   3.38   90.00   85.00   96.63   2.0   1.00
2014   4.25   3.83   92.50   91.50   97.91   2.0   1.00
2015   4.75   4.28   95.00   94.00   97.76   2.0   1.00
2016   5.25   4.72   97.50   96.50   100.36   2.0   1.00
2017   5.50   4.95   97.50   96.50   100.36   2.0   1.00
2018   5.80   5.22   97.50   96.50   100.36   2.0   1.00
2019   5.91   5.32   98.54   97.54   101.44   2.0   1.00
2020   6.03   5.43   100.51   99.51   103.49   2.0   1.00
2021   6.15   5.54   102.52   101.52   105.58   2.0   1.00
2022   6.27   5.64   104.57   103.57   107.71   2.0   1.00
Thereafter escalation rate of 2%

Finding, development and acquisition costs ("FD&A") and finding and development costs ("F&D") both including and excluding future development capital ("FDC") have been calculated in accordance with NI 51-101.  Cequence's finding, development and acquisition costs are as follows:

Proved   Proved Plus
FD&A Including Change in FDC      
  2012 FD&A Costs ($000s) 78,402   78,402
  2012 Change in FDC ($000s) 110,374   206,102
  2012 Capital Expenditures including change in FDC ($000s) 188,776   284,504
  2012 Reserve Additions (MBOE) 14,595   26,924
  2012 FD&A Including Change in FDC ($/BOE) 12.93   10.57
  3 year average FD&A Including Change in FDC ($/BOE) 16.84   12.20
F&D Including Change in FDC      
  2012 F&D Costs ($000s) 91,660   91,660
  2012 Change in FDC ($000s) 110,374   206,102
  2012 Capital Expenditures including change in FDC ($000s) 202,034   297,762
  2012 Reserve Additions (MBOE) 14,475   26,750
  2012 F&D Including Change in FDC ($/BOE) 13.96   11.13
  3 year average F&D Including Change in FDC ($/BOE) 20.06   14.20
FDC - December 31, 2012 ($000s) 346,773   632,586
FDC - December 31, 2011 ($000s) 236,399   426,484
2012 Change in FDC ($000s) 110,374   206,102
FDC Related to 2012 Net Acquisitions (Dispositions) ($000s) -   -
2012 Change in FDC Excluding FDC on Net Acquisitions (Dispositions) ($000s) 110,374   206,102

  (1) In addition to F&D costs, Cequence also calculates FD&A costs which incorporate both the costs and associated reserve additions related to acquisitions net of any dispositions during the year. Since acquisitions can have a significant impact on Cequence's annual reserve replacement costs, the Company believes that FD&A costs provide a more meaningful portrayal of Cequence's cost structure.

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. 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.

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 fiscal 2012, the ratio between the average price of West Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was approximately 33:1 ("Value Ratio"). The Value Ratio is obtained using the 2012 WTI average price of $94.14 (US$/Bbl) for crude oil and the 2012 NYMEX average price of $2.83 (US$/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.

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

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