Cequence Energy announces first quarter financial results, updated independent reserves evaluation and independent resource

Cequence Energy announces first quarter financial results, updated independent 
reserves evaluation and independent resource evaluation 
CALGARY, May 13, 2013 /CNW/ - Cequence Energy Ltd. ("Cequence" or the 
"Company") (TSX: CQE) is pleased to announce the financial and operating 
results from the first quarter, an updated independent reserve evaluation with 
an effective date of April 30, 2013 reflecting increases to the reserves as 
compared to the reserves evaluation effective January 1, 2013. In addition, 
Cequence is pleased to announce an independently prepared resource estimates 
for its Simonette properties. 
Financial and Operating Highlights 
The following are financial and operating highlights for the first quarter of 
2013: 


    --  Increased funds flow from operations by 58 percent from the
        prior year to $10.7 million;
    --  Reduced operating costs by 9 percent from the prior year to
        $7.24 per boe;
    --  Reduced total cash costs from prior year by 10 percent to
        $11.32 per boe;
    --  Increased the operating netback by 55 percent from prior year
        to $16.26 per boe;
    --  Successfully completed 5.0 (4.3 net) wells at Simonette and 1
        (0.5 net) wells at Ansell and facility expansion at Simonette;
        and
    --  Closed the acquisition of an additional 19.2 net sections of
        Montney rights at Simonette in April.

Reserve and Resource Highlights

The increase to the Company's reserves reflects continued exploration success 
on its Simonette property in the Deep Basin of Alberta. In light of the 
first quarter drilling program at Simonette, the completion of the acquisition 
of assets from Donnybrook Energy, the divesture of Fir assets and further 
information from previously drilled wells at Simonette and Ansell, Cequence 
engaged GLJ Petroleum Consultants Ltd. ("GLJ") to re-evaluate the Company's 
reserves attributed to Simonette and Ansell and perform a mechanical update on 
the Company's other properties (the "GLJ Reserves Report"). The Company also 
engaged GLJ to evaluate the contingent resources attributable to the Montney, 
Dunvegan and Fahler zones of the Company's Simonette properties (the "GLJ 
Resource Report") and to calculate the Discovered Petroleum initially in Place 
("DPIIP"). The GLJ Reserve Report and GLJ Resources Report are dated May 9, 
2013 and effective April 30, 2013 and are collectively referred to herein as 
the "GLJ Report". The following are highlights from the GLJ Report:
    --  Increased proved reserves by 21% from December 31, 2012 to 55.5
        MMBOE (previously 46 MMBOE);
    --  Increased proved plus probable reserves by 24% from December
        31, 2012 to 113 MMBOE (previously 91 MMBOE);
    --  Pre-tax net present value (using a discount rate of 10%) of the
        Company's total proved reserves as at April 30, 2013 increased
        31% to M$549,121 ($2.39 per share) and 12% on a proved plus
        probable basis to M$1,052,742 ($4.99 per share);
    --  The GLJ Report estimated contingent resources of 18.5 MMBOE
        (best estimate) to 82.5 MMBOE (high estimate); and
    --  The GLJ estimate of DPIIP for the Montney at Simonette is 2.475
        trillion cubic feet ("Tcf").

Financial and Operating
                                                                    % 
                                   2013         2012             Change

Financial ($)                                                          

Production revenue (          
(1))                             22,005       19,864                 11

Comprehensive loss              (5,439)      (7,936)               (31)

Per share, basic and          
diluted                          (0.03)       (0.05)               (40)

Funds flow from               
operations ((2))                 10,652        6,755                 58

Per share, basic and          
diluted                            0.05         0.04                 25

Production volumes                                                     

Natural gas (Mcf/d)              46,306       49,924                (7)

Crude oil (bbls/d)                  608          684               (11)

Natural gas liquids           
(bbls/d)                            496          459                  8

Total (boe/d)                     8,822        9,464                (7)

Sales prices                                                           

Natural gas, including        
realized hedges
($/Mcf)                            3.51         2.44                 44

Crude oil ($/bbl)                 91.90        89.58                  3

Natural gas liquids           
($/bbl)                           52.84        76.63               (31)

Total ($/boe)                     27.72        23.07                 20

Operating Netback             
($/boe)                                                                

Price                             27.72        23.07                 20

Royalties                        (2.63)       (2.53)                  4

Transportation                   (1.59)       (2.08)               (24)

Operating costs                  (7.24)       (7.97)                (9)

Operating netback                 16.26        10.49                 55

Capital Expenditures          
($)                                                                    

Capital expenditures             43,659       40,934                  7

Net acquisitions              
(dispositions) ((4))                 18     (10,942)              (100)

Total capital                 
expenditures                     43,677       29,992                 46

Net debt and working          
capital (deficiency) (
(3))                           (78,365)     (75,132)                  4

Weighted average              
shares outstanding 
(basic and diluted)             200,610      161,856                 24

Undeveloped land (net         
acres)                          204,572      238,600               (14)

(1) Production revenue is presented gross of royalties and realized
    gains 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
    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.

Funds flow from operations increased to $10.7 million for three months ended 
March 31, 2013 compared to $6.8 million for the three months ended March 31, 
2012. The increase in funds flow from operations is due largely to a 10 
percent increase in revenue resulting from higher natural gas prices and a 16 
percent decrease in operating costs. Funds flow from operations is a 
non-GAAP measurement as defined below.

Cequence recorded a comprehensive loss of $5.4 million for the first quarter 
of 2013 compared to a comprehensive loss of $7.9 million in the same period in 
2012. The 2013 loss is a result of unrealized hedging losses of $3.3 million 
and future income tax expense of $2.6 million.

Capital expenditures in the first quarter were $43.7 million compared to $40.9 
million in 2012. Capital expenditures included the drilling of 5 (4.3 net) 
wells at Simonette and 1 (0.5 net) well at Ansell as well as a facility and 
pipeline upgrade at Simonette.

Net debt and working capital at March 31, 2013 was $78,365 compared to $75,132 
at March 31, 2012. Cequence has credit facilities totalling $100 million 
with the next scheduled review of Cequence's credit facility scheduled for May 
31, 2013. Based on the April 30, 2013 reserves Cequence anticipates an 
increase to the credit facility.

Operations Update

Cequence completed 6.0 gross (4.8 net) horizontal wells in the first quarter 
including 3.0 gross (3.0 net) Montney wells, 1.0 gross (0.65 net) Falher well, 
1.0 gross (0.65 net) Dunvegan well and 1.0 gross (0.49 net) Wilrich well. 
Only one well drilled in the first quarter had significant onstream time 
during the first quarter as production additions at Simonette were restricted 
by facilities. Production averaged 8,822 boepd (46.3 mmcfd and 1,104 bbls/d of 
oil and NGL's) in the first quarter compared to 8,951 boepd (47.1 mmcfd and 
1,098 bbls/d of oil and NGL's) in the fourth quarter of 2012.

In April, Cequence completed pipeline work and the expansion of the Simonette 
compression and de-hydration facility at 13-11. Upon completion, total 
corporate production has averaged approximately 11,000 boepd (57.2 mmcfd and 
1,465 bbls/d of oil and NGL's). The 13-11 facility now has 5,000 
horsepower of compression and is currently delivering 52 mmcfd of gross gas 
sales. Cequence has the ability to expand the capacity of this facility to 120 
mmcfd with additional compression. Cequence is also connected to incremental 
processing capacity at the Keyera Simonette gas plant and continues to produce 
gas through that facility.

Three successful Montney wells (3.0 net) were drilled at Simonette in the 
first quarter. Test rates from the first Montney well of the quarter at 3-18 
was previously disclosed and has now been producing for 75 days at an average 
rate of 5.5 mmcfd and 100 bbls/d of condensate per day. A second Montney 
well at 3-21-61-26W5 has been producing for 26 days at an average restricted 
rate of 4.3 mmcfd and 160 bbls/d of condensate. The current rate is 6.0 mmcfd 
and 165 bbls/d of condensate.

The final Montney well of the quarter at 9-21-61-26W5 was completed on March 
26, 2013. The well was drilled to a lateral length of 2,399 meters and 
completed with a 27 stage frac. Stabilized test rates after 3 days were 8.9 
mmcfd and 480 bbls/d of condensate. On test, the well produced nuisance 
amounts of sour gas of approximately 800 ppm. Surface equipment to handle 
the sour content could not be installed prior to spring break up and will 
occur as soon as conditions in the field permit access. If the 
installation does not occur prior to the end of May, first half production 
volumes are expected to be approximately 250 boepd below previous guidance of 
10,000 boepd. With the successful startup of new wells at Simonette, older 
producers were backed out of the system due to high line pressure. Cequence 
estimates that approximately 2,500 boepd, including initial production from 
the 9-21 well, is currently tied-in but not producing.

Cequence previously announced test rates from successful Falher and Dunvegan 
wells at Simonette. The Falher well at 7-6 has now produced for 35 days at 
an average rate of 7.5 mmcfd and 202 bbls/d of condensate which is at the 
Company's model expectation for gas rates, but with a slightly higher 
condensate ratio. The Dunvegan well has produced for 30 days at an average 
rate of 12.2 mmcfd and 170 bbls/d of condensate. The current production rate 
is 16 mmcfd and 170 bbls/d of condensate. The condensate yield of 14 barrels 
per mmcf is lower than expected; however, the total condensate production is 
similar to expected volumes due to the high relative productivity of the well.

Outlook and Recent Developments

Cequence is pleased with the first quarter drilling results and successful 
expansion of its production facilities at Simonette. Cequence has achieved 
record production levels of 11,300 boepd since the commissioning of the 
facility expansion.

The capital program from the preceding two years has focused on the 
delineation and de-risking of the Company's asset base. The emphasis of the 
Montney play will shift towards development in the second half of 2013 with 
pad drilling commencing at Simonette in the third quarter. Cequence expects 
that pad drilling is the most efficient way to develop the Montney and other 
zones at Simonette. To date, Cequence has built twelve pad sites at 
Simonette serviced with gathering systems and water handling capability 
through separate flow lines. Cequence expects to drill 2.0 gross (1.0 net) 
Wilrich wells at Ansell, 1.0 gross (0.65 net) Dunvegan well and 4.0 gross (4.0 
net) Montney wells at Simonette before year end.

Cequence forecasts net debt to be approximately $88 million at December 31, 
2013 or 1.3 times annualized fourth quarter cash flow. To reduce the risk of 
fluctuations in commodity prices, Cequence has hedged approximately 45 percent 
of its 2013 natural gas production at a price of $3.65 per mcf and 20 percent 
of 2014 production at an average price of $4.11 per mcf.

Cequence is pleased to provide the following guidance for the year ending 
December 31, 2013. Cequence provided guidance for the six months ending June 
30, 2013 on February 4, 2013 and included the significant assumptions in the 
annual MD&A dated March 7, 2013. Other than as disclosed in this press 
release, Cequence does not currently anticipate material changes to the six 
month guidance as previously released.
                                                                   2013

Average production, BOE/d ((1))                        10,000-10,500

Exit rate production, BOE/d                                   11,500

Capital expenditures ($)                                  97 million

Operating costs ($ per boe)                                     6.75

Royalties (% revenue)                                               9

Crude - WTI (US$/bbl)                                          95.00

Natural gas - AECO (Cdn$/GJ)( )                                 3.35

Funds flow from operations ($) ((2))                      55 million

December 31, 2013 net debt and working    
capital ((3))                                             88 million

December 31, 2013 net debt to Q4 2013     
annualized cash                                                  1.3

Basic shares outstanding ((4))                         210.9 million

(1) Comprised of 53.1 mmcf/d of natural gas and 1,350 boe/d of 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
    and demand credit facilities and excluding other liabilities.

(4) Includes the 10.3 million shares issued April 15, 2013 on the
    acquisitions of certain Montney assets from Donnybrook Energy

Reserves

GLJ prepared an independent evaluation of the oil, natural gas liquids and 
natural gas reserves attributable to the properties of Cequence. The GLJ 
Report was produced using a full evaluation of the Simonette and Ansell 
properties using first quarter drilling program results. The reserves 
attributed to the remaining properties of the Company were mechanically 
updated from the December 31, 2012 reserve information presented in the 
Company's Annual Information Form, after giving effect to the acquisition and 
disposition of certain properties. Production from the period of January 1 
to April 30 totalled 1.2 MMBOE.

The tables below are a summary of the oil, NGL and natural gas reserves 
attributable to the properties of Cequence as at April 30, 2013, the net 
present value of future net revenue and the total future net revenue 
attributable to the Company's reserves, in all cases as based on forecast 
price and cost assumptions. In addition, a reconciliation of the proved and 
proved plus probable reserves of the Company as at April 30, 2013 relative to 
December 31, 2012 is provided below. 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        1,018      766      966      784    82,943    73,869    15,808   13,861
  Producing       
Developed           53       40      125       98     7,226     6,386     1,383    1,203
  Non-Producing   
Undeveloped      3,654    2,651    2,060    1,902   195,502   170,723    38,298   33,006 
Total Proved       4,725    3,457    3,151    2,783   285,671   250,978    55,488   48,070 
Probable           5,174    3,486    3,202    2,892   296,874   256,868    57,855   49,190 
Total Proved       9,899    6,943    6,353    5,676   582,545   507,846   113,444   97,260
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 and Discounted at
                                                               (%/year)


                    0           5          10        15        20
Reserves
Category             (M$)        (M$)        (M$)       (M$)      (M$) 
Proved                                                                  
Developed         318,903     261,515     223,291   196,119   175,820
  Producing 
Developed          15,795      12,560      10,331     8,704     7,468
  Non-Producing 
Undeveloped       648,796     441,100     315,498   233,465   176,750 
Total Proved        983,494     715,175     549,121   438,288   360,039 
Probable          1,228,837     744,147     503,621   364,832   276,129 
Total Proved      2,212,331   1,459,322   1,052,742   803,120   636,168
plus Probable 


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


                    0           5          10        15        20
Reserves
Category             (M$)        (M$)        (M$)       (M$)      (M$) 
Proved                                                                  
Developed         318,903     261,515     223,291   196,119   175,820
  Producing 
Developed          15,795      12,560      10,331     8,704     7,468
  Non-Producing 
Undeveloped       554,703     382,399     276,333   205,984   156,714 
Total Proved        889,401     656,474     509,955   410,807   340,003 
Probable            922,666     550,943     366,663   260,797   193,613 
Total Proved      1,812,067   1,207,417     876,619   671,603   533,616
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.

Total Future Net Revenue (Undiscounted)
                                                                             Future                 Future
                                                                               Net                    Net
                                                                             Revenue                Revenue
                                                                             Before                  After
                                                                             Future      Future     Future
                                                 Capital                     Income      Income     Income
                                   Operating   Development   Abandonment       Tax        Tax         Tax


        Revenue    Royalties     Costs        Costs         Costs       Expenses    Expenses   Expenses
Reserves
Category      (M$)        (M$)        (M$)          (M$)           (M$)        (M$)        (M$)       (M$) 
Total      2,218,034     305,080     493,869       420,269         15,322     983,494     94,093     889,401
Proved     
Total      4,793,382     718,832   1,028,219       815,313         23,687   2,212,331    400,263   1,812,067
Proved
plus
Probable   
GLJ employed the following pricing, exchange rate and inflation rate 
assumptions as of April 30, 2013 in the GLJ Report in estimating Cequence's 
reserves data using forecast prices and costs: 


                                                                  Pentanes   
                      Natural Gas            Light Crude Oil        Plus
                             AECO Gas                Edmonton     Edmonton    Inflation    Exchange
            Henry Hub           Price       WTI                                 Rates        Rate

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

Forecast                                                                                         

2013            3.92           3.54        94.73       90.05        105.02        2.0         1.00

2014            4.25           3.83        95.00       94.00        103.40        2.0         1.00

2015            4.75           4.28        95.00       94.00        101.52        2.0         1.00

2016            5.25           4.72        97.50       96.50        102.29        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%

Reconciliation of Company Gross( )Reserves by Product Type

The following table sets forth the changes between the Company's reserve 
volume estimates made as at April 30, 2013 and the corresponding estimates as 
at December 31, 2012, using forecast prices and costs:
                                 Natural Gas            
                    Light and   (associated &
                     Medium         non-                 Total Oil
                    Crude Oil    associated)      NGL    Equivalent

Factors               (Mbbl)         (MMcf)     (Mbbl)      (MBOE)

TOTAL PROVED                                                    

December 31, 2012      3,765        240,205     2,657       46,459

  Extensions &                                          
  Improved
  Recovery              824          46,438       553       9,117

  Technical                                             
  Revisions              10           1,256        14         233

  Discoveries             -              -         -           -

  Acquisitions          201           9,097        86       1,803

  Dispositions            -         (4,575)      (92)       (854)

  Economic                                              
  Factors                 -              -         -           -

  Production           (73)         (6,378)      (68)      (1,204)

April 30, 2013(                                         
(1))                   4,726        286,044     3,154       55,554

TOTAL PROVED PLUS                                       
PROBABLE                                                        

December 31, 2012      7,615        470,386     5,178       91,193

  Extensions &                                          
  Improved
  Recovery             1,635         89,718     1,009       17,597

  Technical                                             
  Revisions             187          12,001       146       2,333

  Discoveries             -              -         -           -

  Acquisitions          536          24,256       230       4,808

  Dispositions            -         (6,853)     (137)      (1,279)

  Economic                                              
  Factors                 -              -         -           -

  Production          (73.3)        (6,378)      (68)      (1,204)

April 30, 2013(                                         
(1))                   9,902        583,130     6,358      113,448

Note:

(1)  Totals may not add due to rounding.

Contingent Resources - Simonette

Cequence retained GLJ to conduct an independent resource evaluation to assess 
contingent resources at Simonette with an effective date of April 30, 2013. 
Contingent resources were evaluated for the Upper Montney Play, Fahler F 
Channel and Dunvegan Channel and are presented herein in aggregate.

All contingent resources evaluated in the GLJ Resources Assessment were deemed 
economic at the effective date of April 30, 2013.

The estimates of volumes of, and the net present value of the future net 
revenue attributable to contingent resources in this news release are derived 
from the GLJ Resources Assessment. The GLJ Resources Assessment was prepared 
in accordance with NI 51-101 by GLJ, an independent qualified reserve 
evaluator.

Summary information regarding contingent resources and net present values of 
future net revenues from contingent resources at Simonette are set forth below:

Gross and Net Contingent Resources at Simonette as at April 30,
2013 ((1)) - Forecast Prices and Costs ((2))
                                      Gross               Net
                                     Contingent Resources((3))
                                Best      High     Best      High
                              (Mbbl)    (Mbbl)   (Mbbl)    (Mbbl)

Light and Medium Oil (MBOE)    2,060     9,145    1,531     6,425

Natural Gas (MMcf)            93,208   416,150   83,144   368,628

NGL (MBOE)                       883     3,997      847     3,904

Total Oil Equivalent (MBOE)   18,478    82,500   16,235    71,767



Summary of Net Present Value of Future Net Revenues of Contingent
Resources at Simonette as at April 30,
2013 - Forecast Prices and Costs ((2)) 


               Before Income Taxes, Discounted at (% per year) ((7))

(M$)              0%        5%      8%     10%     12%     15%     20%

Best
Estimate
(C2) ((4))   395,704   236,930 179,981 151,441 128,345 101,293  69,990

High
Estimate
(C3) ((5)) 2,183,165 1,106,878 788,246 641,212 528,245 402,684 266,529

Notes:

(1)    The contingent resource assessments were prepared in accordance
       with the definitions, standards and procedures contained in the
       Canadian Oil and Gas Evaluation Handbook and NI 51-101.
       Contingent resource is defined in the Canadian Oil and Gas
       Evaluation Handbook as those quantities of petroleum estimated
       to be potentially recoverable from known accumulations using
       established technology or technology under development, but
       which do not currently qualify as reserves or commercially
       recoverable due to one or more contingencies. Contingencies may
       include factors such as economic, legal, environmental,
       political and regulatory matters or a lack of markets.

(2)    The forecast price and cost assumptions utilized in the GLJ
       Report were also utilized by GLJ in preparing the contingent
       resource assessments.

(3)    GLJ prepared the estimates of contingent resource shown for
       Simonette using deterministic principles and methods.
       Probabilistic aggregation of the low and high property estimates
       shown in the table might produce different total volumes than
       the arithmetic sums shown in the table.  Gross means the
       Company's working interest share in the contingent resource
       before deducting royalties.

(4)    Best estimate is considered to be the best estimate of the
       quantity of contingent (C2) resources that will actually be
       recovered.  It is equally likely that the actual remaining
       quantities recovered will be greater or less than the best
       estimate.  Those contingent resources that fall within the best
       estimate have a 50% confidence level that the actual quantities
       recovered will be equal or exceed the estimate.

(5)    High estimate is considered to be an optimistic estimate of the
       quantity of contingent (C3) resources that will actually be
       recovered. It is unlikely that the actual remaining quantities
       of contingent resources recovered will meet or exceed the high
       estimate. Those contingent resources at the high end of the
       estimate range have a lower degree of certainty - a 10%
       confidence level - that the actual quantities recovered will
       equal or exceed the estimate.

(6)    Low estimate is considered to be a conservative estimate of the
       quantity of contingent resources (C1) that will actually be
       recovered. It is likely that actual remaining quantities
       recovered will exceed the low estimate. Those resources included
       in the low estimate range have the highest degree of certainty -
       a 90 percent probability - that the actual quantities recovered
       will equal or exceed the estimate. There were no low estimate
       resources assigned in the GLJ evaluation.

(7)    The net present value of future net revenue attributable to the
       contingent resources does not necessarily represent the fair
       market value of the contingent resources. Estimated abandonment
       and reclamation costs have been included in the evaluation.

The primary contingencies which currently prevent the classification of 
Cequence's contingent resource as reserves include but are not limited to:
    --  preparation of firm development plans, including determination
        of the specific scope and timing of projects;
    --  project sanction;
    --  access to capital markets;
    --  regulatory approvals;
    --  access to required services and field development
        infrastructure;
    --  oil and natural gas prices in Canada;
    --  demonstration of economic viability;
    --  future drilling program and testing results;
    --  further reservoir delineation and studies;
    --  facility design work;
    --  limitations to development based on adverse topography or other
        surface restrictions; and
    --  the uncertainty regarding marketing and transportation of
        petroleum from development areas.

Resignation of Director

As a result of increased commitments, Mr. Paul Colborne has elected to resign 
as a director of the Company effective immediately. The board and management 
of the Company would like to thank Mr. Colborne for his contribution over the 
years, and wish him well in his future endeavours.

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: an 
expected increase to its credit facility; business strategy and objectives; 
development, exploration, acquisition and disposition plans, including the 
anticipated benefits resulting therefrom and the timing thereof; reserve and 
resource quantities and the discounted present value of future net cash flows 
from such reserves or resources; and future production levels and facility 
capabilities. 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.

"Contingent resources" are not, and should not be confused with, petroleum and 
natural gas reserves. "Contingent resources" are defined as those quantities 
of petroleum estimated, as of a given date, to be potentially recoverable from 
known accumulations using established technology or technology under 
development, but which are not currently considered to be commercially 
recoverable due to one or more contingencies. It is also appropriate to 
classify as contingent resource the estimated discovered recoverable 
quantities associated with a project in the early evaluation stage.

There is no certainty that it will be commercially viable to produce any 
portion of the contingent resources or that Cequence will produce any portion 
of the volumes currently classified as contingent resources. The estimates of 
contingent resources involve implied assessment, based on certain estimates 
and assumptions, that the resources described exists in the quantities 
predicted or estimated and that the resources can be profitably produced in 
the future. The net present value of the future net revenue from the 
contingent resources does not necessarily represent the fair market value of 
the contingent resources. Actual contingent resources (and any volumes that 
may be reclassified as reserves) and future production therefrom may be 
greater than or less than the estimates provided herein.

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 the first quarter of 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 
first quarter 2013 WTI average price of $94.30 (US$/Bbl) for crude oil and the 
first quarter 2013 NYMEX average price of $3.48 (US$/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.

DISCOVERED PETROLEUM INITIALLY IN PLACE (DPIIP): DPIIP is equivalent to 
discovered resources and is defined in the Canadian Oil and Gas Evaluation 
Handbook ("COGEH") as that quantity of petroleum that is estimated, as of a 
given date, to be contained in known accumulations prior to production. The 
recoverable portion of discovered petroleum initially-in-place includes 
production, reserves and contingent resources; the remainder is unrecoverable. 
"Contingent Resources" are defined in COGEH as those quantities of petroleum 
estimated to be potentially recoverable from known accumulations using 
established technology or technology under development, but which are not 
currently considered to be economically recoverable due to one or more 
contingencies. Contingencies may include factors such as economic, legal, 
environmental, political, and regulatory matters, or a lack of markets. It is 
also appropriate to classify as contingent resources the estimated discovered 
recoverable quantities associated with a project in the early evaluation 
stage. The Contingent Resources estimates and the DPIIP estimates are 
estimates only and the actual results may be greater or less than the 
estimates provided herein. There is no certainty that it will be commercially 
viable to produce any portion of the resources except to the extent identified 
as proved or probable reserves. "Best estimate" is defined in COGEH with 
respect to entity-level estimates, as the value derived by an evaluator using 
deterministic methods that best represent the expected outcome with no 
optimism or conservatism. If probabilistic methods are used, there should be 
at least a 50 percent probability (P50) that the quantities actually recovered 
will equal or exceed the best estimate.

The TSX has neither approved nor disapproved the contents of this news 
release.







Paul Wanklyn, President and Chief Executive Officer, (403) 
218-8850,pwanklyn@cequence-energy.com

David Gillis, Vice President, Finance and Chief Financial Officer, (403)  
806-4041,dgillis@cequence-energy.com

SOURCE: Cequence Energy Ltd.

To view this news release in HTML formatting, please use the following URL: 
http://www.newswire.ca/en/releases/archive/May2013/13/c6473.html

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

-0- May/14/2013 01:00 GMT


 
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