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Manitok Energy Inc. Announces 2014 Year-End Financial Results, Reserves Evaluation and an Operational Update

CALGARY, ALBERTA--(Marketwired - May 1, 2015) -


Manitok Energy Inc. (the "Corporation" or "Manitok") (TSX VENTURE:MEI) announces its financial and operating results for the year ended December 31, 2014, provides results from its 2014 independent reserves evaluation and provides an operational update. 

Given the current difficult commodity price environment, the Corporation continues to develop its more mature core area at Stolberg while setting itself up for growth in its second core area at Entice. Manitok completed a successful 29 (20.8 net) well drilling program in 2014 in both core areas. Production for the year averaged 4,502 boe/d after taking into account the asset divestiture of approximately 777 boe/d of sour natural gas in the central Alberta foothills region in February 2014 ("Foothills Asset Divestiture").

In Stolberg, Manitok drilled 15 (6.8 net) horizontal wells. Fourteen of the wells (6.5 net) were successfully completed and tied-in to production facilities while one well will be converted to a water injector for the enhanced oil recovery ("EOR") project described below 10 (5.2 net) Stolberg development wells targeted the backlimb of the Cardium structure and four (1.3 net) were drilled into the forelimb. One exploration well targeted the Upper Mannville horizon and identified an entirely new natural gas trend within the Stolberg field, which also has potential throughout Manitok's foothills land base. Production at Stolberg remains strong as the field matured and successfully offset both natural declines and the Foothills Asset Divestiture, increasing the Stolberg field's annualized average production 38% to 4,301 boe/d from 3,126 boe/d in 2013. At year-end 2014, Stolberg production was approximately 58% oil and liquids.

Despite the Corporation's successful drilling results in 2014 it had negative reserve revisions in Stolberg from the gasification of certain wells within the pool. To prevent further gasification, Manitok is currently working to implement a natural gas and water injection EOR project that will optimize the oil recovery. Management believes that the project has a strong probability of being able to recover the reserves, and potentially add more, in subsequent years by increasing the recovery factor of the Cardium pool from its current 9 - 10% to potentially closer to 25%. 

At Entice, the production results have been encouraging to date. With only two wells producing prior to year end and limited production history, the booked reserves to date are conservative given production at Entice to date has exceeded the production profiles in the reserve report. 

Manitok drilled 10 horizontal wells and four vertical test wells across the Entice property, resulting in the identification of 12 different prospective oil and natural gas pools for future drilling. Drilling in the year primarily targeted the Lithic Glauconitic ("Glauc") and Basal Quartz ("BQ") formations. Based on field estimates, current production from Entice, from three horizontal wells, averaged approximately 1,200 boe/d (46% oil) for the month of March 2015. Production rates were over 1,400 boe/d (46% oil) and there continues to be some downtime periods as Manitok continues to work with the third party operator to increase its throughput capability at the gas plant. As a result of the success during 2014, Manitok has identified 49 Glauc and 56 BQ horizontal drilling locations on its current Entice lands.

Manitok is anticipating a prudent approach to development in 2015. The Corporation will focus on maximizing existing production, reducing costs and an abbreviated drilling program that will target drilling locations that can be brought on stream quickly.

The full text of Manitok's year-end results are contained in its audited financial statements as at and for the year ended December 31, 2014, the related management's discussion and analysis and Manitok's Annual Information Form for the year ended December 31, 2014 (the "AIF"), copies of which are available electronically on Manitok's profile on the System for Electronic Document Analysis and Retrieval ("SEDAR") at and also on Manitok's website at

Year-End Results:

  • Production averaged 4,502 boe/d (57% light oil and liquids), a 9% increase over 2013 production of 4,113 boe/d (52% light oil and liquids). The increase was offset by the Foothills Asset Divestiture in February 2014 which contributed 955 boe/d during 2013. Manitok's fourth quarter production averaged 4,072 boe/d (56% light oil and liquids), an 18% decrease from fourth quarter 2013 production of 4,989 boe/d (57% light oil and liquids), which was due mainly to the Foothills Asset Divestiture, which contributed 879 boe/d in the fourth quarter of 2013. 

  • Recorded average production per diluted share growth of 13% and funds from operations per diluted share growth of 14% in 2014 when compared to 2013.

  • Recorded an 11% increase in funds from operations to $46.0 million ($0.65 per diluted share) in 2014 from $41.6 million ($0.57 per diluted share) in 2013.

  • Recorded a 7% increase in operating netback to $35.22/boe in 2014 (excluding the realized gain or loss on financial instruments) from $33.07/boe in 2013.

  • Recorded an unrealized gain on financial instruments of $27.6 million in the fourth quarter of 2014, which highlights the importance of the crude oil and natural gas hedging program for 2015 funds from operations.

  • Capital expenditures were approximately $97.4 million, before of $35.1 million in divestitures and $7.4 million in acquisitions. This included drilling 29 gross (20.8 net) wells for about $75.4 million and about $17.9 million on equipment and facilities in both the Entice and Stolberg areas. 

  • In October 2014, the Corporation completed an acquisition of approximately 290 boe/d (15% oil and liquids) in the Stolberg area, with an effective date of October 1, 2014, for total cash consideration of approximately $7.4 million. 

  • In December 2014, Manitok divested its interest in certain oil and gas infrastructure for $12.3 million after post-closing adjustments. The Corporation has entered into an agreement for the exclusive use of the oil and gas infrastructure, which include facility fees of approximately $1.8 million per annum.

  • At December 31, 2014, net debt was approximately $78.5 million. 

Operational and Financial Summary

    Three months ended
 December 31,
  Twelve months ended
 December 31,
2014   2013   2014   2013  
Average daily production                  
  Light oil (bbls/d)   2,257   2,755   2,508   2,065  
  Natural gas (mcf/d)   10,713   12,868   11,594   11,782  
  NGLs (bbls/d)   30   89   62   84  
  Total (boe/d)   4,072   4,989   4,502   4,113  
Average realized sales price                  
  Light oil ($/bbl)   71.96   82.30   92.57   89.75  
  Natural gas ($/mcf)   3.83   4.03   4.93   3.61  
  NGLs ($/bbl)   67.29   76.48   96.93   78.07  
  Total ($/boe)   50.45   57.21   65.60   57.00  
Undeveloped land (end of period)                  
  Gross (acres)   306,776   375,793   306,776   375,793  
  Net (acres)   290,971   323,907   290,971   323,907  
Netback and Cost ($ per boe)                  
  Petroleum and natural gas sales   50.45   57.21   65.60   57.00  
  Realized gain (loss) on financial instruments   6.67   (0.48 ) (2.31 ) (1.27 )
  Royalty income   -   0.01   0.01   0.25  
  Royalty expenses   (11.61 ) (10.18 ) (19.68 ) (13.69 )
  Operating expenses, net of recoveries   (7.65 ) (8.83 ) (7.34 ) (7.62 )
  Transportation and marketing expenses   (3.17 ) (3.10 ) (3.37 ) (2.87 )
Operating netback(1)   34.69   34.63   32.91   31.80  
  General and administrative expenses, net of recoveries   (4.59 ) (3.53 ) (4.18 ) (3.82 )
  Interest and financing expenses   (1.39 ) (0.37 ) (0.76 ) (0.38 )
  Interest and other income   0.02   0.03   0.02   0.07  
Funds from operations netback(1)   28.73   30.76   27.99   27.67  
Petroleum and natural gas revenue ($000)   18,902   26,260   107,822   85,950  
Funds from operations ($000)(1)   10,766   14,117   45,980   41,554  
  Per share - basic ($)(1)   0.16   0.19   0.66   0.59  
  Per share - diluted ($)(1)   0.16   0.19   0.65   0.57  
Net income (loss) ($000)   (2,774 ) (1,417 ) (3,587 ) 3,615  
  Per share - basic ($)   (0.04 ) (0.02 ) (0.05 ) 0.05  
  Per share - diluted ($)(2)   (0.04 ) (0.02 ) (0.05 ) 0.05  
Common shares outstanding                  
  End of period - basic   65,279,607   74,492,340   65,279,607   74,492,340  
  End of period - diluted   70,588,213   80,099,780   70,588,213   80,099,780  
  Weighted average for the period - basic   65,924,473   72,638,096   69,365,940   70,654,634  
  Weighted average for the period - diluted   66,255,000   74,371,392   70,321,234   72,596,161  
Capital expenditures ($000)   26,949   44,236   69,690   79,365  
Adjusted working capital deficit ($000)(1)   22,795   16,277   22,795   16,277  
Drawn on credit facilities ($000)   53,258   16,237   53,258   16,237  
Long-term financial obligation ($000)   2,500   -   2,500   -  
Total net debt(1) ($000)   78,553   32,514   78,553   32,514  
1. Funds from operations, funds from operations per share, funds from operations netback, operating netback, adjusted working capital deficit and net debt do not have standardized meanings prescribed by generally accepted accounting principles and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. Please refer to Non-GAAP Financial Measures for more information.
2. The basic and diluted weighted average shares outstanding are the same for periods in which the Corporation records a net loss. 

2014 Independent Reserves Evaluation

Sproule Associates Limited ("Sproule"), Manitok's independent qualified reserves evaluator based in Calgary, Alberta, prepared a Reserves Estimation and Economic Evaluation effective December 31, 2014 in respect of Manitok's oil and natural gas properties ("2014 Sproule Report"). Sproule also prepared the reserves estimation and economic evaluation effective December 31, 2013 ("2013 Sproule Report" and together with the 2014 Sproule Report, the "Sproule Reports"). The reserves estimates stated herein are as at December 31, 2014 and 2013 and are extracted from the Sproule Reports. The Sproule Reports have been prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). 

2014 Year-End Reserves Results:

  • The pre-tax net present value discounted at 10% ("NPV10%") of proved plus probable ("P+P") and total proved ("TP") reserves amounted to approximately $183.2 million((1)) and $109.4 million(1) respectively in 2014. Each of these NPV10% amounts does not include any additional value for Manitok's undeveloped land base and seismic. 

  • The net asset value on a P+P NPV10% valuation ("NAV") is about $2.14 per share, assuming an undeveloped land value of $35.0 million (approximately $120 per acre) and net debt of $78.5 million at December 31, 2014.

  • As at December 31, 2014 proved developed producing ("PDP") reserves are 3,730.6 Mboe; TP reserves are 5,688.9 Mboe; and P+P reserves are 11,438.3 Mboe. This includes the Foothills Asset Divestiture in February 2014 and the negative reserve revisions in Stolberg, offset by reserve additions in the Entice area. 

  • Based on the 2014 Sproule Report, Manitok's P+P reserves are comprised of 46% light oil on a boe basis, but represent 87% of the value on a NPV10% valuation basis. 

  • 2014 capital expenditures in the Entice area were approximately $44.2 million which resulted in reserves of 347.8 Mboe PDP, 1,185.8 Mboe TP and 2,828.1 Mboe P+P.

  • The Corporation's three year average finding and development ("F&D") costs including the change in future development capital ("FDC") is $27.39/boe for TP reserves and $21.49/boe for P+P reserves. Recycle ratios consisted of 1.3 and 1.6 times for TP and P+P reserves respectively, based on a 2014 operating netback, excluding the realized loss on financial instruments, of $35.22/boe. The current year F&D is not a true representation of results as it includes a significant negative technical revision of the Stolberg area due to reservoir performance. 

  • Despite the current year negative reserve revisions in Stolberg, the three year average F&D costs including the change in FDC and the negative reserve revisions are $21.50/boe for TP reserves and $17.44/boe for P+P reserves. Recycle ratios consisted of 1.6 and 2.0 times for TP and P+P reserves respectively, based on a 2014 operating netback, excluding the realized loss on financial instruments, of $35.22/boe.

  • In Entice, where Manitok received its first reserve bookings with only 2 wells on production at December 31st 2014, the 2014 F&D costs including the change in FDC are $21.49/boe P+P reserves. Based on a 2014 operating netback of $35.22/boe excluding the realized loss on financial instruments, the P+P recycle ratios is 1.33.

The following table summarizes Manitok's working interest oil and natural gas reserves at December 31, 2014, using the Sproule forecast price assumptions:

Summary of Oil and Natural Gas Reserves
    Light and Medium Oil Natural Gas(2) Natural Gas Liquids Total
Reserve Category   Gross(3)
  Developed Producing   1,739.0 1,218.7 11,401 9,735 91.4 61.5 3,730.6 2,902.6
  Developed Non-Producing   238.2 192.9 1,785 1,673 23.8 17.9 559.7 489.8
  Undeveloped   905.6 646.2 2,791 2,422 27.8 20.4 1,398.5 1,070.3
Total Proved   2,882.8 2,057.8 15,979 13,830 143.1 99.9 5,688.9 4,462.7
Probable   2,422.0 1,764.5 18,571 16,164 232.1 162.8 5,749.4 4,621.2
Total Proved Plus Probable   5,304.8 3,822.3 34,550 29,994 375.2 262.6 11,438.3 9,083.9
1. Based on Sproule's December 31, 2014 forecast prices and costs. The forecast of commodity prices used in the 2014 Sproule Report can be found in the AIF available electronically under the Corporation's profile on the SEDAR website at and on the Corporation's website at
2. Estimates of reserves of natural gas include both associated and non-associated gas. Gross reserves are the Corporation's working interest share before deduction of royalty obligations and without including any royalty interests.
3. Net reserves are the Corporation's working interest share after deduction of royalty obligations, plus royalty interests in such reserves. 
4. Columns may not add due to rounding of individual items.

The following table is a summary of the net present value of future net revenue associated with Manitok's reserves as at December 31, 2014 before deducting future income tax expense and calculated at various discount rates:

Net Present Values of Future Net Revenue Before Income Taxes
  Before Income Taxes
Discounted at (%/year)
Reserve Category 0%
  Developed Producing 101,043   88,458   79,351   72,374   66,839
  Developed Non-Producing 15,220   12,465   10,472   8,970   7,800
  Undeveloped 32,000   24,848   19,575   15,568   12,445
Total Proved 148,262   125,771   109,398   96,912   87,085
Probable 145,290   100,537   73,782   56,326   44,214
Total Proved Plus Probable 293,552   226,308   183,179   153,238   131,299
1. Based on Sproule's December 31, 2014 forecast prices and costs. The forecast of commodity prices used in the 2014 Sproule Report can be found in the AIF available electronically under the Corporation's profile on the SEDAR website at and on the Corporation's website at
2. Columns may not add due to rounding of individual items.
3. Estimates of future net revenues whether discounted or not do not represent fair market value.

The following table is a reconciliation of Manitok's gross reserves as derived from the Sproule Reports:

Reserves Reconciliation of Gross Reserves(1)

  Gross Proved (Mboe)   Gross Probable (Mboe)   Gross Proved Plus Probable (Mboe)  
December 31, 2013 9,457.0   7,262.5   16,719.5  
Discoveries, extensions and infill drilling 2,594.3   2,112.0   4,706.3  
Acquisitions (dispositions) (3,143.6 ) (928.8 ) (4,072.4 )
Technical revisions(2) (1,613.7 ) (2,704.3 ) (4,318.1 )
Economic factors (7.3 ) 7.8   0.5  
Production over the year (1,597.6 ) -   (1,597.6 )
December 31, 2014 5,689.1   5,749.3   11,438.3  
1. Gross reserves are the Corporation's working interest share before deduction of royalty obligations and without including any royalty interests.
2. Technical revisions resulting from category changes and the reservoir performance since inception in the Stolberg area.
3. Columns may not add due to rounding of individual items.

Capital Program Efficiency

The following table outlines Manitok's estimate of its F&D costs per boe and finding, development and acquisition ("FD&A") costs per boe, and including the change in FDC, recycle ratios, reserves replacement and reserve life index on a TP and P+P basis. 

  2014   2013   Three Year Weighted Average  
Capital Expenditures (M$)            
Exploration and Development(1)(2) 94,347   80,598   223,364  
Acquisitions/(Dispositions) (27,690 ) (3,413 ) (31,755 )
Total Capital Expenditures 66,657   77,185   191,609  
Change in FDC (M$)            
Total Proved (4,062 ) (6,423 ) 13,561  
Proved Plus Probable 1,709   (377 ) 18,896  
F&D and FD&A costs including change in FDC            
  F&D - TP(2)(3) $92.76   $25.33   $27.39  
  F&D - P+P(2)(3) $247.06   $23.89   $21.49  
  FD&A - TP(2)(4) N/A   $24.16   $40.05  
  FD&A - P+P(2)(4) N/A   $22.87   $31.94  
  Recycle Ratio - TP(5) 0.4   1.3   1.3  
  Recycle Ratio - P+P(5) 0.1   1.4   1.6  
Reserve Replacement            
  Total Proved N/A   195 % 129 %
  Proved Plus Probable N/A   224 % 166 %
Reserve Life Index (years)(6)            
  Total Proved 3.8   5.2      
  Proved Plus Probable 7.7   9.2      
1. Exploration and development expenditures excludes $2.8 million (2013 - $1.8 million) of capitalized overhead costs.
2. The aggregate of the exploration and development costs incurred in the most recent financial year and change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
3. The 2014 F&D costs are not a true representation of results as it includes significant negative technical revisions in the Stolberg area due to reservoir performance.
4. The 2014 FD&A costs are negative due to asset divestments and negative technical revisions in the Stolberg exceeding total reserve additions.
5. Recycle ratio is calculated as the operating netback excluding realized gains or losses on financial instruments divided by F&D costs. 
6. Reserve Life Index is based on annualized 2014 fourth quarter production volumes.

2015 Production and Operational Update

Carseland (Southeast Alberta)

Three of four multi-stage fractured horizontal wells tied into third party facilities within the Carseland field have achieved both 30 and 60 day initial production ("IP30" and "IP60") rates. These wells represent the potential future results from two reservoir discoveries made by the Corporation in 2014. A summary of the test rates, IP30 and IP60 rates for the Carseland wells are summarized in the table below. The first discovery from the Glauc formation, is exemplified by the well at 16-32-22-25W4, which has obtained an IP30 rate of 820 boe/d (43% oil) and an IP60 rate of 750 boe/d (44% oil). The well is currently flowing and restricted by a downhole choke and pressure depletion in the Glauc reservoir has been minimal.

The second discovery is from the middle BQ formation and is represented by wells at 14-33-22-25W4 and 3-28-22-25W4 which have also obtained IP30 and IP60 rates. The 14-33 well had an IP30 rate 604 boe/d (33% oil) and an IP60 rate of 445 boe/d (34% oil). The 3-28 well had an IP30 rate of 150 boe/d (77% oil) and an IP60 rate of 154 boe/d (71% oil). The 14-33 well continues to flow on its own while the 3-28 well is equipped with a downhole pump.

Carseland Test, IP30 and IP60 Rates Summary Table
    Test Rates IP30 Rates IP60 Rates
Well Oil Gravity (API) Oil (Boe/d) Natural Gas (Mmcf/d) Total (Boe/d) Oil (Boe/d) Natural Gas (Mmcf/d) Total (Boe/d) Oil(Boe/d) Natural Gas (Mmcf/d) Total (Boe/d
16-32-22-25W4 41° 321 2.9 804 351 2.8 820 327 2.5 750
14-33-22-25W4 28° 152 3.2 688 198 2.4 604 151 1.8 445
03-28-22-25W4 30° 135 0.4 205 118 0.2 150 109 0.3 154
15-32-22-25W4 40° 328 2.6 761            
03-09-23-25W4 27° 177 1.1 367            
102/7-9-23-25W4 32° 19 1.0 181            

The fourth well, 15-32-22-25W4, is a Glauc well that tested at 761 boe/d. The well is tied-in however, the third party facility is unable to efficiently process the associated natural gas due to its high liquid content. In the short term, the facility operator is planning to conduct minor equipment modifications and process optimization in May that will improve the NGL processing capability of the plant. Both Manitok and the facility operator are evaluating alternatives that would allow for an additional 10 Mmcf/d of gas processing along with improving natural gas liquid recovery before the end of 2015. Manitok is also in the process of tying in the 3-16-23-25W4 satellite facility that will allow the well 3-9-23-25W4 a lower BQ well, which tested at 367 boe/d and the well 102/7-9-23-25W4 (formerly 100/2-9-23-25W4) middle BQ well, which tested at 181 boe/d. Engineering design work is complete and equipment has been procured. Given the processing issues at the third party plant, Manitok will tie-in the wells after the plant modifications in May 2015. Based on field estimates total production from the Entice area averaged 1,200 boe/d (46% oil) during the month of March 2015.

Corporate Production

Based on field estimates, Manitok's production averaged 4,556 boe/d (51% oil) during the first quarter of 2015 with intermittent disruptions at Stolberg and processing issues at Entice. Manitok continues to experience intermittent disruptions in the TransCanada natural gas pipeline in the Stolberg area associated with required repairs on its system. TransCanada Pipeline has advised Manitok that the restriction could be in place periodically, throughout the year. The Corporate production of 4,556 boe/d was achieved with a contribution from only two BQ wells and one Glauc well at Carseland which were only producing for a little less than two thirds of the quarter and were restricted as a result of the high condensate content in the natural gas. 

2015 Guidance

The Corporation will not drill any wells in Entice or Stolberg during the first half of 2015, due to the current low commodity price environment. Manitok anticipates about $6.0 to $6.5 million of capital expenditures in the first half of 2015 that would include completions and facilities capital required on wells already drilled. Approximately 60% to 65% of cash flow will be applied towards debt reduction in the first half of 2015. Manitok will evaluate its production and the level of commodity prices in the second quarter of 2015 before planning and executing the bulk of its 2015 capital expenditure program in the second half of the year.


In 2015, Manitok has hedged 1,500 bbls/d of crude oil at an average price of $93.67 and 16,000 GJs/d of natural gas at an average price of $3.48 after the deferred premium. The Corporation has also recently added option collar transactions for 1,000 bbls/d of crude oil from $68.70 to $86.20 CAD WTI net of the deferred premium for both the 2016 and 2017 calendar years.

Credit Facilities

Manitok's credit facilities were reviewed by the lender subsequent to December 31, 2014, and due to the current commodity price environment and negative technical revisions of proved plus probable reserves in the Stolberg area, the operating demand loan facility was reduced from $90.0 million to $75.0 million.

Conference Call

A conference call to discuss the 2014 year end results will begin at 6:00 a.m. Mountain Time (8:00 a.m. Eastern Time) on Friday, May 1, 2015. To participate please dial 416-340-2218 (local) or 866-223-7781 (toll free in North America) or 00-800-6578-9868 (international toll free) 10 minutes prior to the scheduled start time. 

About Manitok

Manitok is a public oil and gas exploration and development company focusing on conventional oil and gas reservoirs in the Canadian foothills and southeast Alberta. The Corporation will utilize its experience to develop the untapped conventional oil and liquids-rich natural gas pools in both the foothills and southeast Alberta areas of the Western Canadian Sedimentary Basin.

Forward-looking Statements

This press release contains forward-looking statements. More particularly, this press release contains statements concerning operational and drilling plans, the development and growth potential of Manitok's properties, the anticipated timing of implementation of EOR system and the degree of recovery of additional reserves as a result of such implementation and the anticipated timing of optimization of NGL processing facility, including addition of a refrigeration plant to such facility. The forward-looking statements in this press release are based on certain key expectations and assumptions made by Manitok, including expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, the successful application of technology, prevailing weather conditions, commodity prices, royalty regimes and exchange rates and the availability of capital, labour and services. 

Although Manitok believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Manitok can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimates; the uncertainty of estimates and projections relating to production, costs and expenses; and health, safety and environmental risks), uncertainty as to the availability of labour and services, commodity price and exchange rate fluctuations, unexpected adverse weather conditions, general business, economic, competitive, political and social uncertainties, capital market conditions and market prices for securities and changes to existing laws and regulations. Certain of these risks are set out in more detail in the AIF, which is available on Manitok's SEDAR profile at

Forward-looking statements are based on estimates and opinions of management of Manitok at the time the statements are presented. Manitok may, as considered necessary in the circumstances, update or revise such forward-looking statements, whether as a result of new information, future events or otherwise, but Manitok undertakes no obligation to update or revise any forward-looking statements, except as required by applicable securities laws.

Any references in this press release to initial and/or final raw test or production rates and/or "flush" production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter. These test results are not necessarily indicative of long-term performance or ultimate reserve recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production.

Non-GAAP Financial Measures

This press release contains references to measures used in the oil and natural gas industry such as "funds from operations", "funds from operations netback", "funds from operations per share", "operating netback", "adjusted working capital deficit", and "net debt". These measures do not have standardized meanings prescribed by generally accepted accounting principles ("GAAP") an, therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding the Corporation's liquidity and its ability to generate funds to finance its operations.

Funds from operations should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with GAAP, as an indicator of Manitok's performance or liquidity. Funds from operations is used by Manitok to evaluate operating results and Manitok's ability to generate cash flow to fund capital expenditures and repay indebtedness. Funds from operations denotes cash flow from operating activities as it appears on the Corporation's Statement of Cash Flows before decommissioning expenditures and changes in non-cash operating working capital. Funds from operations is also derived from net income (loss) plus non-cash items including deferred income tax expense, depletion and depreciation expense, impairment expense, stock-based compensation expense, accretion expense, unrealized gains or losses on financial instruments and gains or losses on asset divestitures. Funds from operations netback is calculated on a per boe basis and funds from operations per share is calculated as funds from operations divided by the weighted average number of basic and diluted common shares outstanding. Operating netback denotes petroleum and natural gas revenue and realized gains or losses on financial instruments less royalty expenses, operating expenses and transportation and marketing expenses calculated on a per boe basis. Adjusted working capital deficit includes current assets less current liabilities excluding the current portion of the amount drawn on the credit facilities, the current portion of the fair value of financial instruments and the deferred premium on financial instruments. Manitok uses net debt as a measure to assess its financial position. Net debt includes current assets less current liabilities excluding the current portion of the fair value of financial instruments and the deferred premium on financial instruments, plus the long-term financial obligation.

Barrels of Oil Equivalent

The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. Per boe amounts have been calculated using a conversion ratio of six thousand cubic feet (6 mcf) of natural gas to one barrel (1 bbl) of crude oil. The boe conversion ratio of 6 mcf to 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. 

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

(1) Estimates of future net revenues whether discounted or not do not represent fair market value.

Manitok Energy Inc.
Massimo M. Geremia
President & Chief Executive Officer

Source: Marketwired (Canada) (May 1, 2015 - 1:22 AM EDT)

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