Cequence Energy announces operational update and 2014 reserves and financial and operating results

CALGARY, March 5, 2015 /CNW/ - Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is pleased to announce its operating and financial results for the periods ended December 31, 2014, an operational update and the results of its year-end independent reserve evaluation.  The Company's Audited Consolidated Financial Statements and Management's Discussion and Analysis available at cequence-energy.com and on SEDAR at www.sedar.com.

Highlights

Highlights for 2014 include:

  • Increased annual funds flow by 38 percent to $70.7 million or $0.33 per share;
  • Increased annual average production by 7 percent to 10,932 boepd;
  • Reduced fourth quarter operating costs by 9 percent over Q4 2013 to $6.67 per boe;
  • Realized a gain of $92 million on the disposition of the Ansell property for $140 million;
  • Maintained a strong balance sheet through declining commodity prices with a trailing debt to cash flow ratio of 1.0 times;
  • Initiated a 13-well horizontal development program at Simonette including successfully executing multi-well pad drilling and more intense completion techniques;
  • Efficiently added reserves with proved plus probable finding, development and acquisition costs ("FD&A costs") of $10.26 and proved FD&A costs of $3.97;
  • Increased proved developed producing reserves by 16 percent from the prior year to 18.7 mmboe;
  • Increased proved plus probable reserves to 118 mmboe with an NPV 10% of $854 million; and
  • Achieved current production of 12,500 boepd with 2,700 boepd of production tested and awaiting tie-in or shut-in due to infrastructure constraints.

"Our drive to become a focused Deep Basin Montney producer continued in 2014." said Paul Wanklyn, President and CEO.  "We monetized our Ansell property for a significant gain and, despite losing 1,600 boepd through the sale of the property, Cequence achieved yearly average production of 10,932 boepd or 7 percent growth over 2013.  Important changes were made to our completion methods since Q1 2014 which resulted in the successful completion of 10 Montney wells and 3 Cretaceous wells through our fall/winter drilling program. We are extremely pleased with both the execution success achieved by our team, and the initiation of pad style drilling operations at our Simonette Field"

Operations Update

During the winter program Cequence drilled 13 gross (10.95 net) horizontal wells including 10 gross (9.0 net) Montney wells from three separate pad locations.  Drilling performance continues to improve, with recent Montney pad wells six days faster than earlier pad wells.  Completion intensity was increased to 1.0 tonne of sand per lateral meter compared to historical stimulations of 0.5 tonne of sand per lateral meter.  This 100 percent increase in completion intensity, was accomplished with only a 10 percent increase in average completion costs.  The last 3 wells drilled from the 1-32 padsite however had an average well cost of $8.7 MM per well or 8 percent lower than 2013/14 completion intensity wells.  As a result of the development style of this year's capital program, seven of the 10 Montney completions were flowed in line to sales during clean up.

Montney Well Results

Cumulative Production Rates



Final Test Rate

IP 30 Production

Pad

Wells

Gas

Free Condensate

Gas

Free Condensate


#

MMCFD

BBLD

bbl/mmcf

MMCFD

BBLD

bbl/mmcf









01-32

6

33.3

1695

50.9

26.5

848

32.0









12-26

2

12.4

222

17.9

9.5

156

16.4









15-15

2

13.6

368

27.1

Forecast on Production March 15









Average per well

5.9

229

38.8

4.5

126

28.0

Dunvegan and Falher Well Results

Production Rates



Final Test Rate

IP 30 Production

Well

Zone

Gas

Free Condensate

Gas

Free Condensate



MMCFD

BBLD

bbl/mmcf

MMCFD

BBLD

bbl/mmcf









11-12

Dunvegan

6.8

118

17.4

8.1

174

21.5









8-18

Falher

2.1

15

7.1

1.6

13

8.2









2-11

Dunvegan

8.9

113

12.7

On Production March 4









Average per well

5.9

83

14.1

4.9

94

19.2

Production and Facilities

Cequence completed the expansion of its Simonette 13-11-62-27W5 facility in January resulting in current capacity of 100 mmcfd.  The Simonette field was down for 7 days in January, associated with the final installation of the new equipment and was re-started on January 13th, 2015.  Since January 15th, Cequence has averaged approximately 12,200 boe per day despite pipeline maintenance restrictions on the TCPL system and related increased industry volume constraints that cascaded onto the Alliance/Aux Sable system.  The TCPL Pipeline maintenance impacts may last until Q3 2015 and will restrict peak production volumes from the Simonette property.

Current field estimated production is 12,500 boed with 1,200 boed of net tested production expected to be tied-in in mid-March, with another 1,500 boed shut-in due to infrastructure capacity restrictions.  Despite these curtailments and a strategically reduced capital budget, Cequence expects production to average 11,500 boed for the year, or a 5 percent increase compared to 2014. 

Financial and Operating Highlights

(000's except per share and per unit amounts)

Three months ended

December 31,

Twelve months ended

December 31,



2014

2013

%  Change

2014

2013

%  Change

Financial ($)








Production revenue (1)


25,566

28,483

(10)

136,893

105,617

30

Comprehensive income (loss)


(4,422)

(827)

(435)

79,368

(2,613)

3,137

Per share - basic


(0.02)

(0.00)

n/a

0.38

(0.01)

3,900

Per share - diluted


(0.02)

(0.00)

n/a

0.37

(0.01)

3,800

Funds flow from operations (2)


13,745

14,855

(7)

70,650

51,312

38

Per share, basic


0.07

0.07

-

0.33

0.25

32

Per share, diluted


0.06

0.07

(14)

0.33

0.25

32

Production volumes








Natural gas (Mcf/d)


49,265

53,433

(8)

55,826

52,705

6

Crude oil (bbls/d)


97

119

(18)

118

125

(6)

Natural gas liquids (bbls/d)


541

569

(5)

583

524

11

Condensate (bbls/d)


872

800

9

927

750

24

Total (boe/d)


9,720

10,394

(6)

10,932

10,183

7

Sales prices








Natural gas, including realized hedges ($/Mcf)


3.92

3.82

3

4.54

3.57

27

Crude oil ($/bbl)


73.15

78.56

(7)

89.76

86.46

4

Natural gas liquids ($/bbl)


29.67

44.46

(33)

41.10

39.72

3

Condensate ($/bbl)


70.59

88.44

(20)

94.04

92.52

2

Total ($/boe)


28.59

29.79

(4)

34.31

28.42

21

Netback ($/boe)








Price


28.59

29.79

(4)

34.31

28.42

21

Royalties


(1.25)

(1.85)

(32)

(3.51)

(2.32)

51

Transportation


(1.48)

(1.62)

(9)

(1.48)

(1.60)

(8)

Operating costs


(6.67)

(7.33)

(9)

(7.63)

(7.66)

-

Operating netback


19.19

18.99

1

21.69

16.84

29

General and administrative


(2.27)

(1.65)

38

(2.21)

(1.95)

13

Interest(5)


(1.87)

(1.77)

6

(1.87)

(0.93)

101

Cash netback


15.05

15.57

(3)

17.61

13.96

26

Capital expenditures ($)








Capital expenditures


56,472

51,578

9

180,215

117,909

53

Net acquisitions (dispositions) (4)


(2,381)

(47)

4,966

(150,782)

(2,675)

5,537

Total capital expenditures


54,091

51,531

5

29,433

115,234

(74)

Net debt and working capital (deficiency) (3)


(71,354)

(111,433)

(36)

(71,354)

(111,433)

(36)

Weighted average shares outstanding








Basic


211,028

210,917

-

210,990

207,950

1

Diluted


212,069

210,917

1

214,092

207,950

3

(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.

(3)

Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities, demand credit facilities, principal value of senior notes and excluding other liabilities.

(4)

Represents the cash proceeds from the sale of assets and cash paid for the acquisition of assets, as applicable.

(5)

Represents finance costs less amortization on transaction costs and accretion expense on senior notes and provisions. 

FINANCIAL

Funds flow from operations increased to $70.7 million for 2014 compared to $51.3 million for the 2013.  The increase in funds flow from operations is due largely to higher realized oil and natural gas prices and a 7 percent increase in production volumes.  Funds flow from operations was $13.7 million for the three months ended December 31, 2014, compared to $14.9 million for the three months ended December 31, 2013.  Fourth quarter production volumes were down six percent from 2013 and average sales prices decreased by four percent from the prior year.  

Comprehensive income for the year ended December 31, 2014 was $79.4 million compared to a $2.6 million loss in 2013.  The increase in earnings is due to gains realized on the sale of oil and gas properties in the year of $99.8 million and higher commodity prices, offset partially by increases in future income taxes, depletion and impairment.  Cequence recorded a comprehensive loss of $4.4 million for the fourth quarter of 2014 compared to comprehensive loss of $0.8 million in the same period in 2013. The loss in the fourth quarter of 2014 is a result of impairment charges of $18.4 million offset by an unrealized hedging gain $10.6 million.

Capital expenditures, prior to acquisition and dispositions, were $56.5 million in the fourth quarter of 2014 and $180.2 million for the year ended December 31, 2013.  For the year ended December 31, 2014, Cequence participated in drilling 20 (14.9 net) wells.  Net of acquisitions and dispositions of $150.8 million, capital expenditures were $29.4 million for the year ended December 31, 2014.

The Company is well positioned to weather the current period of low commodity prices.  The Company exited 2014 with available credit facilities of $195 million versus net debt of $71.4 million.  On a trailing twelve month basis, the net debt to cash flow ratio is 1.0 times. Net debt is comprised of $60 million in senior notes carrying a five year term and a working capital deficiency of $11.4 million.   The Company's senior credit facility was undrawn at December 31, 2014.

Outlook and Guidance

Balance sheet strength remains critically important to the Company's strategy of maximizing shareholder value through profitable growth.  In response to weak commodity prices, the Company reduced capital spending in the first half of 2015 to $22 million and spending will approximate cash flow over this period.  Budgeted capital expenditures for 2015 are $60 million and will include (5.0)4.2 net horizontal wells to be drilled at Simonette in the second half of 2015.  The Company will continue to monitor fluctuations in commodity prices and may adjust capital spending based on the Company's hedge position and short to medium term crude oil and natural gas prices.

Cequence anticipates production growth of five percent in 2015 based largely on the success of the 2014/15 winter drilling program.  Annual production volumes are expected to average 11,500 boepd for the year ended December 31, 2014.  

First quarter production is expected to average 11,500 boepd, compared to 12,500-13,000 boepd as previously guided due to onstream delays and recent maintenance to the TransCanada system and the resulting spillover of production volumes filling existing Alliance capacity.  Cequence expects the maintenance issues to be ongoing through September 2015.

The Company has hedged approximately half of its 2015 natural gas production at an average price of $3.84 Cdn per mcf and will continue to actively hedge production to protect future capital spending programs.  Based on AECO natural gas prices of $2.65/GJ, annual funds flow is forecast to be approximately $40 million resulting in net debt of approximately $90 million at December 31, 2015. 



Previous 2015

(3 months)

 Revised 2015

(3 months)

Guidance

2015

Average production, BOE/d (1)


12,500-13,000

11,500

11,500

Funds flow from operations ($) (2)


$12,000

$10,000

$40,000

Funds flow from operations per share (2)


$0.06

$ 0.05

$0.19

Capital expenditures, prior to dispositions ($) (3)


$22,000

$22,000

$60,000

Wells drilled


5(4.7)

5(4.7)

10(9.2)

Operating and transportation costs ($ per boe)


$8.20

$8.80

$8.80

G&A costs ($ per boe)


$1.90

$2.50

$2.50

Royalties (% revenue)


10

10

10

Crude – WTI (US$/bbl)


$50.00

$50.00

$50.00

Natural gas – AECO (Cdn$/GJ) 


$2.65

$2.65

$2.65

Period end, net debt and working capital deficiency ($) (4)


$85,000

$85,000

$90,000

Basic shares outstanding


211,000

211,000

211,000

Notes:


(1)

Average production estimates on a per BOE basis are comprised of 84% natural gas and 16% 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, demand credit facilities and the aggregate principal amount of the senior notes and excluding other liabilities.

Reserves

The following highlights are based on the reserve report effective December 31, 2014 (the "GLJ Report") prepared by GLJ Petroleum Consultants ("GLJ"):

  • Increased proved developed producing reserves by 16 % from the prior year to 18.7 mmboe;
  • Increased proved reserves by 3% from the prior year to 57.1 MMBOE;
  • Increased proved plus probable reserves by 4% from the prior year to 118.1 MMBOE;
  • Achieved FD&A costs (including changes to FDC) of $10.26 per boe on a proved plus probable basis and $3.97 per boe on a proved basis;
  • Achieved F&D costs (including changes to FDC) of $13.82 per boe on a proved plus probable basis and $16.66 per boe on a proved basis;
  • Achieved an FD&A recycle ratio of 2.1 times based on the 2014 operating netback of $21.69;
  • Net present value before income taxes of the Company's proved plus probable reserves is  $854 million or $4.05 per share (using a discount rate of 10%); and
  • Replaced 227 percent of production with proven plus probable reserve additions.

In accordance with NI 51101, 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, Natural Gas and NGL Reserves



Light and Medium

Crude Oil


NGL


Natural Gas


Total Oil Equivalent

Reserves Category

Gross

Net


Gross

Net


Gross

Net


Gross

Net


(Mbbl)


(Mbbl)


(Mbbl)


(Mbbl)


(MMcf)


(MMcf)


(MBOE)


(MBOE)

Proved













Developed Producing

1,595

1,106


997

854


96,604

84,834


18,693

16,099


Developed Non-Producing

523

363


273

240


25,423

22,176


5,033

4,299


Undeveloped

3,537

2,586


1,774

1,643


168,474

148,229


33,390

28,934

Total Proved

5,655

4,055


3,043

2,737


290,500

255,239


57,115

49,332

Probable

6,315

4,328


3,200

2,926


308,409

268,558


60,917

52,014

Total Proved plus Probable

11,971

8,383


6,243

5,663


598,909

523,797


118,032

101,346

Notes:


(1)

Columns may not add due to rounding.

(2)

"Gross" reserves means the Company's working interest (operated and non-operated) share before deduction of royalties payable to others and without including any royalty interests of the Company.

(3)

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

Summary of Net Present Value of Future Net Revenue

Reserves Category

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


0


5


10


15


20


10


(M$)


(M$)


(M$)


(M$)


(M$)


($/mcfe)


Proved








Developed Producing

288,076

232,727

195,984

170,101

150,970

2.03


Developed Non-Producing

88,906

68,135

55,167

46,415

40,140

2.14


Undeveloped

471,949

296,967

196,335

133,513

91,870

1.13

Total Proved

848,931

597,829

447,485

350,029

282,980

1.51

Probable

1,157,793

651,276

406,738

270,841

187,791

1.30

Total Proved plus Probable

2,006,724

1,249,105

854,223

620,870

470,771

1.40








Reserves Category


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

0


5


10


15


20


(M$)


(M$)


(M$)


(M$)


(M$)

Proved







Developed Producing

288,076

232,727


195,984

170,101

150,970


Developed Non-Producing

88,906

68,135

55,167

46,415

40,140


Undeveloped

412,255

265,896

179,061

123,389

85,675

Total Proved

789,237

566,758

430,211

339,905

276,786

Probable

867,481

481,142

294,925

191,954

129,495

Total Proved plus Probable

1,656,719

1,047,900

725,137

531,859

406,281

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, 2015 in the GLJ Report in estimating Cequence's reserves data using forecast prices and costs: 

Year


Natural Gas


Light Crude Oil


Pentanes Plus


Inflation Rates



Exchange Rate


Henry Hub


AECO Gas

Price


WTI


Edmonton


Edmonton


($US/MMBtu)


($Cdn/MMBtu)


($US/bbl)


($Cdn/bbl)


($Cdn/bbl)


%/year


($US/$Cdn)

Forecast








2015


3.31

3.31

62.50


64.71


69.24

2.0

0.850

2016

3.75

3.77

75.00


80.00

85.60

2.0

0.875

2017

4.00

4.02

80.00

85.71

91.71

2.0

0.875

2018

4.25

4.27

85.00

91.43

97.83

2.0

0.875

2019

4.50

4.53

90.00

97.14

103.94

2.0

0.875

2020

4.75

4.78

95.00

102.86

110.06

2.0

0.875

2021

5.00

5.03

98.54

106.18

113.62

2.0

0.875

2022

5.25

5.28

100.51

108.31

115.89

2.0

0.875

2023

5.50

5.53

102.52

110.47

118.20

2.0

0.875

2024

5.68

5.71

104.57

112.67

120.56

2.0

0.875

Thereafter escalation rate of 2%

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





Proved


Proved Plus

Probable

FD&A Including Change in FDC




2014 FD&A Costs ($000s)

29,433

29,433


2014 Change in FDC ($000s)

(5,871)

(63,886)


2014 Capital Expenditures including change in FDC ($000s)

23,562

93,319


2014 Reserve Additions (MBOE)

5,939

9,091


2014 FD&A Including Change in FDC ($/BOE)

3.97

10.26


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

11.68

10.77

F&D Including Change in FDC




2014 F&D Costs ($000s)

180,215

180,215


2014 Change in FDC ($000s)

30,625

133,859


2014 Capital Expenditures including change in FDC ($000s)

210,840

314,074


2014 Reserve Additions (MBOE)

12,657

22,727


2014 F&D Including Change in FDC ($/BOE)

16.66

13.82


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

14.12

11.63




FDC – December 31, 2014 ($000s)

381,427

849,135

FDC – December 31, 2013 ($000s)

387,298

785,249

2014 Change in FDC ($000s)

(5,871)

63,886

FDC Related to 2014 Net Acquisitions (Dispositions) ($000s)

36,496

69,973

2014 Change in FDC Excluding FDC on Net Acquisitions (Dispositions) ($000s)

30,625

133,859

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 and exploration and evaluation expenditures of $180,215, net cash expenditures on property acquisition and dispositions of ($150,782).

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

The press release contains references to terms commonly used in the oil and gas industry.  Netback is not defined by IFRS in Canada and is referred to as a non-GAAP measure.  Netbacks equal total revenue less royalties, operating costs and transportation costs.  Management utilizes this measure to analyze operating performance. 

Funds flow from operations is a non-GAAP term that represents cash flow from operating activities before adjustments for decommissioning liability expenditures, proceeds from the sale of commodity contracts and changes in non-cash working capital. The Company evaluates its performance based on earnings and funds flow from operations. The Company considers funds flow from operations to be a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company's calculation of funds flow from operations may not be comparable to that reported by other companies. Funds flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of income (loss) per share.

Operating and cash netback is not defined by IFRS in Canada and is referred to as a non-GAAP measure. Operating netback equals total revenue less royalties, operating costs and transportation costs. Cash netback equals the operating netback less general and administrative expenses and interest expense. Management utilizes these measures to analyze operating performance. 

Non-GAAP measures do not have a standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers.

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 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.

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 2014, the ratio between the average price of West Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was approximately 22:1 ("Value Ratio"). The Value Ratio is obtained using the 2014 WTI average price of $93.03 (US$/Bbl) for crude oil and the 2014 NYMEX average price of $4.26 (US$/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

RELATED LINKS
www.sabretooth.ca

Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890