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

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.

FINANCIAL AND OPERATIONAL HIGHLIGHTS  

(000's except          Three months ended               Year ended
per share and             December 31                   December 31
per unit
amounts)
                                         %                           % 
                
                      2012     2011  Change      2012       2011 Change

Financial ($)                                                          

Production          21,939   23,527     (7)    75,650    101,996   (26)
revenue ((1))

Comprehensive          666 (15,598)     104  (17,673)   (20,158)   (12)
income (loss)

Per share,             (0)   (0.10)     100    (0.10)     (0.14)   (29)
basic and
diluted

Funds flow          11,603   10,002      16    33,724     42,262   (20)
from
operations (
(2))

Per share,            0.06     0.06       -      0.19       0.29   (34)
basic and
diluted

Production                                                             
volumes

Natural gas         47,125   47,203       -    47,137     47,825    (1)
(Mcf/d)

Crude oil              583      503      16       622        575      8
(bbls/d)

Natural gas            515      509       1       512        464     10
liquids
(bbls/d)

Total (boe/d)        8,951    8,879       1     8,990      9,010      -

Sales prices                                                           

Natural gas,          3.49     3.59     (3)      2.67       4.03   (34)
including
realized
hedges ($/Mcf)

Crude oil            86.78    97.15    (11)     85.02      92.60    (8)
($/bbl)

Natural gas          45.83    73.19    (37)     54.76      71.99   (24)
liquids
($/bbl)

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           (6.55)   (8.60)    (24)    (7.43)     (9.02)   (18)
costs

Operating            16.45    14.52      13     12.07      15.64   (22)
netback

Capital                                                                
Expenditures
($)

Capital             23,997   56,335    (57)    91,658    149,601   (39)
expenditures                            131

Net                    644        -     100  (13,258)   (23,023)   (42)
acquisitions
(dispositions)
((4))

Total capital       24,641   56,335    (56)    78,400    126,578   (38)
expenditures

Net debt and      (45,869) (51,442)    (11)  (45,869)   (51,442)   (11)
working
capital
(deficiency) (
(3))

Weighted           194,224  161,818      20   178,209    147,558     21
average shares
outstanding 
(basic and
diluted)

Undeveloped        204,215  254,400    (20)   204,215    254,400   (20)
land (net
acres)

Wells drilled       3(2.7)     7(5)            7(5.8)          1       
gross (net)
                                                       

(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.

Financial

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."

Reserves

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                                                 Total Oil
                      Crude Oil              NGL         Natural Gas         Equivalent


              Gross      Net    Gross      Net     Gross       Net    Gross      Net
Reserves
Category          (Mbbl)   (Mbbl)   (Mbbl)   (Mbbl)   (MMcf)    (MMcf)    (MBOE)   (MBOE) 
Proved                                                                                    
Developed          809      629      863      666    73,622    65,829   13,942   12,266
  Producing 
Developed           49       39      120       93     6,752     6,001    1,295    1,132
  Non-Producing 
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       7,615    5,347    5,173    4,521   469,783   407,992   91,086   77,867
plus Probable 
Notes: 
(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
                     Before Future Income Tax Expenses Discounted at
                                                             (%/year)


                    0           5        10        15        20
Reserves
Category             (M$)        (M$)       (M$)      (M$)      (M$) 
Proved                                                                
Developed         253,091     205,774   173,947   151,218   134,221
  Producing 
Developed          14,499      11,282     9,087     7,500     6,305
  Non-Producing 
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      1,677,479   1,108,568   797,124   604,154   474,441
plus Probable 


                      After Future Income Tax Expenses Discounted at
                                      (%/year)


                    0         5        10        15        20
Reserves
Category             (M$)       (M$)      (M$)      (M$)      (M$) 
Proved                                                              
Developed         257,072   209,659   177,743   154,930   137,855
  Producing 
Developed          14,499    11,282     9,087     7,500     6,305
  Non-Producing 
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      1,422,469   956,643   696,862   533,504   422,427
plus Probable 
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, 2013 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    Exchange
                             Price                                            Rates        Rate

Year       ($US/MMBtu)   ($Cdn/MMBtu)   ($US/bbl) ($Cdn/bbl)   ($Cdn/bbl)     %/year    ($US/$Cdn)

Forecast                                                                                       

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 Plus
                                                Proved     Probable

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

Note:

  (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.



Paul Wanklyn, Chief Executive Officer, (403) 
218-8850,pwanklyn@cequence-energy.com David Gillis, Chief Financial Officer, 
(403) 806-4041,dgillis@cequence-energy.com

SOURCE: Cequence Energy Ltd.

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CO: Cequence Energy Ltd.
ST: Alberta
NI: OIL ERN 

-0- Mar/07/2013 23:57 GMT