Cequence Energy announces 2015 independent reserves evaluation

CALGARY, Feb. 23, 2016 /CNW/ - Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is pleased to announce the results of its year-end reserve evaluation as prepared by its qualified independent reserve evaluator.  The audit of the Company's 2015 annual financial statements has not been completed.  Accordingly, all financial amounts relating to the 2015 financial statements referred to in this news release are unaudited and represent management's best estimates.  Readers are advised that these financial estimates are subject to audit and may be subject to change as a result.

GLJ Petroleum Consultants ("GLJ") prepared the reserves report effective December 31, 2015 (collectively referred to herein as the "GLJ Report") for the oil, natural gas liquids and natural gas reserves attributable to the properties of Cequence. The GLJ Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 ("NI 51-101"). The following highlights are based on the GLJ Report dated February 10, 2016:

  • Increased proved developed producing reserves by 4 percent from the prior year to 19,473 mboe, with a reserve replacement of 122 percent on 2015 production of 3.5 mboe;
  • Increased proved reserves by 9 percent from the prior year to 62,513 mboe, with a reserve replacement ratio of  255 percent;
  • Increased proved plus probable reserves by 7 percent from the prior year to 125,983 mboe, with a reserve replacement ratio of 328 percent;
  • Increased proved oil reserves by 49 percent to 8,433 Mbbl and proved plus probable oil reserves by 43% to 17,123 Mbbl.
  • Net present value before income taxes of the Company's proved plus probable reserves is  $482 million or $2.28 per share (using a discount rate of 10%); and
  • The GLJ estimate of net DPIIP for the Upper Montney at Simonette is 3.6 trillion cubic feet ("Tcf") on 50,602 net acres. Forecast recovery of DPIIP totals 15% for 2P reserves.

The Company efficiently added reserves throughout its 2015 capital program by focusing on improving well performance and controlling costs.  Improved drilling and completion techniques incorporating longer horizontals at Simonette effectively lowered Cequence's future development capital and resulted in highly efficient reserve addition costs for 2015. 

  • Achieved FD&A costs (including changes to FDC) of ($2.71) per boe on a proved plus probable basis, $10.73 per boe on a proved basis, and $3.81 per boe on a proved developed producing basis;
  • Achieved F&D costs (including changes to FDC) of $2.34 per boe on a proved plus probable basis, $15.66 per boe on a proved basis; and $14.08 per boe on a proved developed producing basis.
  • Generated a strong FD&A recycle ratio of 3.0 and 1.1 times, respectively, for proved developed producing and total proved reserves using a 2015 operating netback of $11.53/boe including hedges. 

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. The calculated NPVs include a deduction for estimated future well abandonment and reclamation costs.  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, Natural Gas and NGL Reserves



Crude and Tight Oil (4)


NGL


Natural Gas  (5)


Total Oil Equivalent

Reserves Category


Gross

(Mbbl)

Net
(Mbbl)


Gross

(Mbbl)

Net

(Mbbl)


Gross

(MMcf)

Net

(MMcf)


Gross

(MBOE)

Net

(MBOE)





Proved














Developed Producing


2,253

1,517


852

586


98,204

87,112


19,473

16,622


Developed Non-Producing


168

133


57

38


4,981

4,519


1,055

924


Undeveloped


6,012

4,517


1,666

1,306


205,845

183,525


41,985

36,411

Total Proved


8,433

6,167


2,575

1,930


309,031

275,157


62,513

53,956

Probable


8,689

5,871


2,608

1,879


313,037

275,280


63,470

53,630

Total Proved plus Probable


17,123

12,038


5,183

3,808


622,067

550,437


125,983

107,586














Notes:


(1)

Columns may not add due to rounding.

(2)

"Gross" reserves means the Company's working interest (operated and nonoperated) 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 nonoperated) share after deduction of royalty obligations plus the Company's royalty interests in reserves.

(4)

Crude and Tight Oil includes product types of light and medium crude oil, tight oil and heavy crude oil.

(5)

Natural Gas includes product types of shale gas and conventional natural gas.

Summary of Net Present Value of Future Net Revenue

Reserves Category


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


0

(M$)


5

(M$)


10

(M$)


15

(M$)


20

(M$)


10

($/mcfe)

Proved














Developed Producing


190,405


156,774


131,061


113,160


100,188


1.31


Developed Non-Producing


10,908


8,518


6,947


5,845


5,035


1.25


Undeveloped


333,322


179,693


94,380


44,767


14,732


0.43

Total Proved


534,635


344,985


232,388


163,773


119,955


0.72

Probable


906,896


446,563


249,642


151,118


95,953


0.78

Total Proved plus Probable


1,441,531


791,548


482,030


314,891


215,908


0.75

Reserves Category


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


0

(M$)


5

(M$)


10

(M$)


15

(M$)


20

(M$)

Proved












Developed Producing


190,405


156,774


131,061


113,160


100,188


Developed Non-Producing


10,908


8,518


6,947


5,845


5,035


Undeveloped


333,322


179,693


94,380


44,767


14,732

Total Proved


534,635


344,985


232,388


163,773


119,955

Probable


678,160


345,871


199,266


123,551


79,857

Total Proved plus Probable


1,212,795


690,856


431,654


287,324


199,812












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, 2016 in the GLJ Report in estimating Cequence's reserves data using forecast prices and costs: 

Year


Natural Gas


Light Crude Oil


Pentanes Plus






Henry Hub


AECO Gas
Price


WTI


Edmonton


Edmonton


Inflation Rates


Exchange Rate


($US/MMBtu)


($Cdn/MMBtu)


($US/bbl)


($Cdn/bbl)


($Cdn/bbl)


%/year


($US/$Cdn)

Forecast















2016


2.60


2.76


44.00


55.86


60.79


2.0


0.725

2017


3.10


3.27


52.00


64.00


68.48


2.0


0.750

2018


3.30


3.45


58.00


68.39


73.17


2.0


0.775

2019


3.50


3.63


64.00


73.75


78.91


2.0


0.800

2020


3.70


3.81


70.00


78.79


84.30


2.0


0.825

2021


3.90


3.90


75.00


82.35


88.12


2.0


0.850

2022


4.10


4.10


80.00


88.24


94.41


2.0


0.850

2023


4.30


4.30


85.00


94.12


100.71


2.0


0.850

2024


4.50


4.50


87.88


96.48


103.24


2.0


0.850

2025


4.60


4.60


89.63


98.41


105.30


2.0


0.850

Thereafter escalation rate of 2%








The following table summarizes the elements of future net revenue attributable to reserves estimated using forecast prices and costs.


Revenue
($000s)


Royalties
($000s)


Operating
Costs ($000s)


Development
Costs ($000s)


Abandonment
and
Reclamation
Costs ($000s)


Future Net
Revenue
Before
Income
Taxes ($000s)


Income
Taxes
($000s)


Future Net Revenue
After
Income Taxes ($000s)

Proved
Reserves

2,038,606


262,776


738,833


458,067


44,294


534,635


-


534,635

Proved
Plus
Probable
Reserves

4,559,699


650,651


1,607,970


799,625


59,922


1,441,531


228,735


1,212,795

Future Net Revenue by Product Type

Reserves Category


Product Type


Future Net Revenue Before
Income Taxes (3)
(discounted at 10% per year) ($000s)


Unit Value $/boe


Unit Value $/MMcf

Proved Reserves


Light and Medium Oil (1)


12,509


11.17


1.86



Conventional Natural Gas (2)


50,305


4.05


0.68



Shale Natural Gas


169,573


4.19


0.70



Total


232,388


4.31


0.72

Proved Plus Probable
Reserves


Light and Medium Oil (1)


25,224


12.02


2.00



Conventional Natural
Gas (2)


98,095


4.20


0.70



Shale Natural Gas


358,712


4.37


0.73



Total


482,030


4.48


0.75










Notes:


(1)

Includes solution gas and other by-products

(2)

Including by-products but excluding solution gas

(3)

Other Company revenue and costs not related to a specific production group have been allocated proportionately to production groups.  Unit values are based on Company Net Reserves.

FD&A and F&D both including and excluding FDC have been calculated as described in the Additional Advisories section of this news release.  Cequence's finding, development and acquisition costs are as follows:







Proved
Developed
Producing


Proved


Proved Plus
Probable

FD&A Including Change in FDC







2015 FD&A Costs ($000s)

18,560


18,560


18,560


2015 Change in FDC ($000s)

(2,375)


76,640


(49,510)


2015 Capital Expenditures including change in FDC ($000s)

16,185


95,200


(30,950)


2015 Reserve Additions (MBOE)

4,254


8,871


11,386


2015 FD&A Including Change in FDC ($/BOE)

3.81


10.73


(2.71)


3 year average FD&A Including Change in FDC ($/BOE)

10.84


10.70


7.55

F&D Including Change in FDC







2015 F&D Costs ($000s)

62,261


62,261


62,261


2015 Change in FDC ($000s)

(2,375)


76,640


(35,598)


2015 Capital Expenditures including change in FDC ($000s)

59,886


138,901


26,663


2015 Reserve Additions (MBOE)

4,254


8,871


11,386


2015 F&D Including Change in FDC ($/BOE)

14.08


15.66


2.33


3 year average F&D Including Change in FDC ($/BOE)

18.61


14.60


10.03







FDC – December 31, 2015 ($000s)

575


458,067


799,625

FDC – December 31, 2014 ($000s)

2,950


381,427


849,135

2015 Change in FDC ($000s)

(2,375)


76,640


(49,510)

FDC Related to 2015 Net Acquisitions (Dispositions) ($000s)

-


-


(13,912)

2015 Change in FDC Excluding FDC on Net Acquisitions (Dispositions) ($000s)

(2,375)


76,640


(35,598)

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. 

(2)

Capital expenditures for the FD&A calculation include cash expenditures on property and equipment of $62,261, net cash expenditures on property acquisition and dispositions of ($43,701).  Total capital expenditures of $62,261 include $20,849 of expenditures related to the 13-11 refrigeration plant incurred prior to its sale in June 2015. 

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; the Company's 2015 capital program; development, exploration, acquisition and disposition plans, including the anticipated benefits resulting therefrom and the timing thereof; reserve quantities and the discounted present value of future net cash flows from such reserves; future production levels; facility expansion and drillings plans; the timing of the impacts of the TransCanada Pipeline system; expected future oil and gas prices; and the timing of well completions. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, 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

This press release contains metrics commonly used in the oil and natural gas industry, such as "finding and development costs," "recycle ratio," "finding, development and acquisition costs," "operating netbacks," and "reserve replacement." These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

FD&A costs and F&D costs have been calculated in accordance with NI 51-101. F&D costs refers to all current year net capital expenditures, excluding property acquisitions and dispositions with associated reserves, and including changes in FDC on a proved or proved plus probable basis.  FD&A costs incorporate both costs and associated reserve additions related to acquisitions net of any dispositions during the year.  Further information on how the Company calculates F&D and FD&A costs is available in the Company's 2014 Annual Information Form filed on SEDAR.  Management uses F&D costs as a measure to assess the performance of the Company's resources required to locate and extract new hydrocarbon reservoirs. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.  FD&A and F&D costs used by Cequence may not be comparable to similar measures used by other issuers.

Recycle ratio is measured by dividing the operating netback by appropriate F&D or FD&A costs per boe for the year. Operating netback is calculated using production revenues, including realized gains and losses on commodity hedging, less royalties, transportation and operating expenditures, calculated on a per boe equivalent basis. Reserve replacement ratio measures the amount of reserves added to a Company`s reserve base during the year relative to the amount of oil and gas produced.  Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time.

Discovered Petroleum Initially-In-Place ("DPIIP") was prepared by GLJ in accordance with the COGE Handbook. DPIIP is 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 DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable.

This news release contains estimates of the net present value of the Company's future net revenue from its reserves.  Such amounts do not represent the market value of the Company's reserves.

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 2015, the ratio between the average price of West Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was approximately 19:1 ("Value Ratio"). The Value Ratio is obtained using the 2015 WTI average price of $48.82 (US$/Bbl) for crude oil and the 2015 NYMEX average price of $2.63 (US$/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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