Yangarra Announces Year End 2013 Financial, Operating Results and Reserves

1) Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves. 2) Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure) (CNW Group/Yangarra Resources Ltd.)

CALGARY, March 25, 2014 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX-V:YGR) releases its 2013 financials and reserves.

2013 Financial and Operating Highlights

During the year ended December 31, 2013 the Company completed the following significant milestones:

  • Average daily production was 2,206 boe/d, a 15% increase from 2012.

  • Funds flow from operations were $26 million ($0.21 per share - basic), a 76% increase from 2012.

  • Earnings before interest, taxes, depletion & depreciation, amortization and changes in commodity contracts ("EBITDA") was $27 million.

  • Operating costs, including $1.26/boe of transportation costs, were $7.56/boe.

  • Operating netback of $36.18 per boe, a 42% increase from the $25.48 per boe reported in 2012.

  • G&A costs of $2.06/boe, which represents an 18% decrease from 2012.

  • Royalties at 5% of oil and gas revenue.

  • $1.2 million of realized hedging gains.

  •  Fourth quarter 2013 production was 2,764 boe/d with funds flow from operations of $8 million ($0.06 per share - basic).

  •  Total capital expenditures were $47 million versus $19.8 million in 2012.  With the equity raise late in 2013 the Company accelerated the fourth quarter capital expenditures to $26 million.

  • As at December 31, 2013, the Company had a current bank debt, subordinated debt and working capital deficit, excluding mark to market on commodity contracts and flow-through share obligations, of $44.6 million compared to $36.3 million at December 31, 2012.
    • The annualized fourth quarter debt to cash flow ratio was 1.4 : 1.

Reserve Report Highlights:

  • Increased proved plus probable reserves by 39% to 17.5 million barrels of oil equivalent and proved reserves by 32% to 9.4 million barrels of oil equivalent.

  • Proved plus probable reserves, net present value discounted at 10% ("NPV 10") at December 31, 2013 was $251.1 million, an increase of 50% compared to December 31 2012.

  • Replaced 2013 production by 283% on a proved basis and 614% on a proved plus probable basis.

  • Achieved finding and development costs including changes in future capital, of $14.07/boe ($8.18 excluding changes in future capital) on proved plus probable reserves and $17.58/boe on proved ($15.25 excluding changes in future capital).

  • Generated a finding and development recycle ratio of 2.57 times on proved plus probable reserves including changes in future capital (4.42 times excluding changes in future capital) based on the Company's 2013 operating netback of $36.18 per barrel of oil equivalent.

  • Reserve life index of 16.0 years on a total proved plus probable basis based on the Company's December, 2013 production rate of 3,000 boe/d.

  • Future development costs (proved plus probable) of $125 million which is 2.5 times the 2014 capital budget.

  • Net Asset Value of $206 million as at December 31, 2013, which is $1.40 per common share.

Operations Update

During the first quarter of 2014 the Company drilled 6 gross (5.9 net) wells in the Cardium formation. A total of 4 gross (3.9 net) wells were put on production during the quarter with the final 2 (2.0 net) expected to be on stream at quarter end.   The Company experienced 11 days of shut-in production (approximately 1,200 boe/d) due to the TransCanada pipeline rupture near Rocky Mountain House and an additional 150 boe/d average for the quarter of Keyera curtailments at other facilities.  The Company expects first quarter production to be approximately 2,800 boe/d and full year guidance remains at 3,200 boe/d.  The Company will continue to drill through break-up as conditions permit, with 6 gross (5.2 net) wells planned for the second quarter.

President's Message to Shareholders

Yangarra is currently drilling its 71st horizontal well in Central Alberta. The experience gained by drilling this many wells with the team we have put in place over the past four years has been key to reducing costs  to a point where we are top decile in drilling and completions, operating costs and G&A costs. We are currently concentrating on "oilier" targets in the Cardium and Glauconite horizons where we have significant inventory.  We also have a large undrilled inventory in "gassier" Cardium, Glauconite and Rock Creek zones that we will drill as natural gas prices continue to improve. These "gassier" targets are extremely "liquids rich", however, the "oilier" targets still command higher internal rates of return (IRR). Half cycle IRR's in 2013 were 65%, re-cycle ratios were 2.57 (P+P including changes in future capital) in 2013 and annual production growth is forecast to be 45% in 2014.

A recent farm-in was negotiated in which the Company added significant acreage to its Cardium inventory. Yangarra has been active at crown land sales and has been successful closing deals with industry to add additional future drilling locations. The Company has added two future drilling locations for every location drilled in each of the past four years and we have visibility to do the same going forward.

Yangarra is focused on adding shareholder value and to properly gauge this we have calculated full-cycle rates of return, presented below which we believe is more indicative of value creation.  All capital costs for each year are included in this calculation including land, infrastructure, geological work, etc.  The chart shows the impact of focusing on returns rather than focusing on growth.

According to Yangarra's 2013 year end engineering report the Company is valued at $1.40 per share (2P (pre-tax) at PV 10, net of debt). The financing late last year provided the necessary liquidity to achieve the outstanding reserve additions generated by the Company in the fourth quarter of 2013. There is significant additional intrinsic value not booked in the reserve report in our 53,000 acres (including farm-in acreage) of undeveloped Cardium and Glauconite land and for our 39,040 acre net Duvernay land position.

TD Bank recently opined that liquids rich Duvernay lands may be worth $2,000 - $4,000 per acre in Pembina/Willesden Green which positions our shareholders with great option value in this rapidly developing play.  Yangarra has recently retained the services of two experienced shale professionals to develop the asset with plans in progress to drill a vertical strata-graphic test well.

I would like to thank the shareholders for their support. I thank my colleagues at Yangarra for their ongoing dedication to the development of the Company.  They have delivered seamless, reliable operations and demonstrated their ability to quickly interpret, react and adapt to the technical results of our development drilling efforts.  I also wish to take this opportunity to thank my fellow directors for their support and leadership.

Financial Summary

                                     
      2013     2012     Year ended
      Q4     Q3     Q4     2013     2012     2011
Statements of Comprehensive Income (Loss)                                    
Petroleum & natural gas sales   $ 11,087,956   $ 9,372,931   $ 4,842,343   $ 34,726,657   $ 21,327,157   $ 20,742,259
Net income (loss) for the period (before tax)   $   1,576,908   $ 39,646   $ (2,409,766)   $ 4,146,706   $ 21,174   $ 4,872,697
                                     
Net income (loss) for the period   $ 750,851   $ 11,330   $ 340,623   $ 2,585,699   $ (217,712)   $ 1,385,698
Net income (loss) per share - basic and diluted   $ 0.01   $ 0.00   $ 0.00   $ 0.02   $ (0.00)   $ 0.01
                                     
Statements of Cash Flow                                    
Funds flow from (used in) operating activities   $ 7,975,588   $ 6,378,207   $ 3,168,328   $ 25,648,666   $ 14,588,405   $ 16,341,180
Funds flow from (used in) operating activities per share - basic and diluted   $ 0.06   $ 0.05   $ 0.03   $ 0.21   $ 0.12   $ 0.15
Cash from (used in) operating activities   $ 10,757,178   $ 3,683,552   $ 4,163,347   $ 27,077,123   $ 17,016,431   $ 6,664,849
                                     
Statements of Financial Position                                    
Property and equipment   $ 152,971,016   $ 135,892,343   $ 121,842,378   $ 152,971,016   $ 121,842,378   $ 119,374,219
Total assets   $ 169,798,021   $ 154,773,403   $ 138,894,114   $ 169,798,021   $ 138,894,114   $ 141,291,043
Working Capital (deficit), excluding MTM on commodity contracts   $ 36,794,243   $ 42,594,542   $ (36,301,842)   $ 36,794,243   $ (36,301,842)   $ (34,028,162)
Subordinated Debt   $ 7,786,632   $    -     $                 -     $ 7,786,632   $                  -     $   -  
Non-Current Liabilities   $ 7,523,351   $ 13,971,180   $ 12,274,710   $ 7,523,351   $ (12,274,710)   $ (9,752,766)
Shareholders equity   $ 95,583,587   $ 82,022,213   $ 79,689,765   $ 95,583,587   $ (79,689,765)   $ (76,627,244)
                                     
Weighted average number of shares - basic     127,219,336     121,718,245     121,711,723     123,101,587     120,663,095     105,960,324
Weighted average number of shares diluted     128,322,269     121,987,009     121,711,723     123,101,587     120,663,095     113,781,122
                                     
                                     

Operations Summary

                               
      2013     2012     Year Ended
      Q4     Q3     Q4     2013     2012
                               
Daily production volumes                              
  Natural gas (mcf/d)     8,303     6,983     4,607     6,583     5,586
  Oil (bbl/d)     683     547     418     556     350
  NGL's (bbl/d)     605     450     304     422     341
  Royalty income                              
    Natural gas (mcf/d)     405     299     956     557     1,273
    Oil (bbl/d)     1     1     (7)     1     3
    NGL's (bbl/d)     24     26     57     37     77
   Combined (boe/d 6:1)     2,764     2,238     1,700     2,206     1,914
                               
Revenue                              
Petroleum & natural gas sales - Gross   $ 11,087,956   $ 9,372,931   $ 4,842,343   $ 34,726,657   $ 21,327,157
Royalty income     177,335     195,468     216,693     1,108,750     2,024,819
Commodity contract settlement     271,387     (326,435)     535,585     1,181,080     907,863
Total sales     11,536,678     9,241,964     5,594,621     37,016,487     24,259,839
                               
Royalty expense     (557,278)     (701,597)     (3,370)     (1,796,832)     (1,057,597)
Petroleum & natural gas sales - Net   $ 10,979,400   $ 8,540,367   $ 5,591,251   $ 35,219,655   $ 23,202,242
Change in fair value of contracts   $ (2,217,286)   $ (2,411,102)   $ (209,267)   $ (6,928,607)   $ 3,889,986
Total Revenue - Net of royalties   $ 8,762,114   $ 6,129,265   $ 5,381,984   $ 28,291,048   $ 27,092,228
                               

Pricing Summary

                               
        2013       2012       Year Ended
        Q4       Q3       Q4       2013       2012
Realized Pricing (Including commodity contracts)                                        
  Oil ($/bbl)   $   85.56   $   96.51   $   83.76   $   92.08   $   84.09
  NGL  ($/bbl)   $   52.08   $   53.33   $   25.09   $   54.32   $   46.78
  Gas ($/mcf)   $   3.92   $   3.05   $   3.02   $   3.53   $   2.49
                                         
Realized Pricing (Excluding commodity contracts)                                        
  Oil ($/bbl)   $   84.98   $   102.99   $   77.78   $   90.93   $   83.07
  NGL  ($/bbl)   $   51.45   $   60.77   $   18.27   $   52.91   $   45.92
  Gas ($/mcf)   $   3.67   $   2.57   $   2.94   $   3.25   $   2.23
                                         
Oil Price Benchmarks                                        
  West Texas Intermediate ("WTI") (US$/bbl)   $   97.46   $   105.81   $   88.22   $   97.97   $   94.21
  Edmonton (C$/bbl)   $   86.58   $   103.65   $   83.99   $   93.11   $   87.02
                                         
Natural Gas Price Benchmarks                                        
  AECO gas (Cdn$/GJ)   $   3.15   $   2.82   $   3.06   $   3.65   $   2.79
                                         
Foreign Exchange                                        
  U.S./Canadian Dollar Exchange   $   0.953   $   0.963   $   1.009   $   0.971   $   1.000
                                         

Netback Summary

                                                 
        2013         2012         Year Ended
        Q4         Q3         Q4         2013         2012
                                                 
Sales Price   $   44.67     $   43.94     $   34.39     $   44.59     $   31.74
  Royalty income       0.70         0.95         1.39         1.38         2.89
  Royalty expense       (2.19)         (3.41)         (0.02)         (2.23)         (1.51)
  Production costs       (6.20)         (5.45)         (9.65)         (6.30)         (6.81)
  Transportation costs       (1.27)         (1.47)         (0.95)         (1.26)         (0.84)
Operating netback   $   35.70     $   34.56     $   25.16     $   36.18     $   25.48
                                                 
  G&A and other (excludes non-cash items)       (2.07)         (1.76)         (2.25)         (2.06)         (2.52)
  Finance expenses       (2.59)         (2.32)         (2.65)         (2.32)         (2.13)
Cash flow netback       31.04         30.49         20.26         31.80         20.82
  Depletion and depreciation       (15.96)         (18.05)         (18.52)         (17.50)         (20.67)
  Impairment       -           -           (19.82)         -           (5.76)
  Gain on sale of property and equipment       -           -           4.15         -           0.93
  Accretion       (0.16)         (0.15)         (0.14)         (0.18)         (0.13)
  Stock-based compensation       -           (0.38)         -           (0.36)         (0.71)
  Unrealized gain (loss) on financial instruments       (8.72)         (11.71)          (1.34)         (8.60)         5.55
  Deferred income tax       (3.25)         (0.14)         17.59         (1.94)         (0.34)
Net Income (loss) netback   $   2.95     $   0.06     $    2.18     $   3.21     $   (0.31)
                                                 

Capital Summary

                                                 
        2013           2012         Year Ended
Cash Additions       Q4         Q3         Q4         2013         2012
                                                 
Land, acquisitions and lease rentals   $   (261,263)     $   307,274     $   240,777     $   184,606     $   734,910
Drilling and completion       18,958,090         6,725,516         6,679,886         35,705,499         19,727,708
Geological and geophysical       170,565         417,101         337,060         756,870         1,002,064
Equipment       1,490,863         1,036,654         1,758,120         7,595,294         2,812,328
Other Asset Additions       100,771         80,681                   318,233         171,521
    $   20,459,026     $   8,567,226     $   9,015,843     $   44,560,502     $   24,448,531
                                                 
Disposition of Property and Equipment   $   -       $   -       $   (4,650,000)       -         (4,650,000)
Net Capital Additions   $   20,459,026     $   8,567,226     $   4,365,843     $   44,560,502     $   19,798,531
                                                 
 Exploration & evaluation assets additions     2,461,506                 
$
    2,461,506       

Oil and Gas Reserves

The following tables summarize certain information contained in the independent reserves report prepared by AJM Deloitte as of December 31, 2013. The report was prepared in accordance with 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").

Summary of Oil and Gas Reserves

    (based on forecast price and costs)

Reserves Category       Light and
Medium Oil
(Mbbl)
          Natural Gas
Liquids
(Mbbl)
          Natural
Gas
(MMcf)
   
    W.I.
Gross
  Co.Share
Gross
  Net   W.I.
Gross
  Co.Share
Gross
  Net   W.I.
Gross
  Co.Share
Gross
  Net
Proved Developed Producing     988   993   820   711   754   539   12,095   13,209   11,130
Proved Developed Non-Producing   215   216    194   65    67   53   1,634     1,679   1,511
Proved Undeveloped   1,276   1,289   1,118   866    923   705   14,806   16,304   14,351
Total Proved   2,479   2,498   2,132   1,642   1,744   1,297   28,535   31,192   26,992
Probable   2,392   2,401   2,031   1,308   1,357   1,010   24,227   25,590   22,739
Total Proved Plus Probable   4,871   4,899   4,163   2,950   3,101   2,307   52,762   56,782   49,731
                                     

Reserves Category     Total BOE
as at December 31, 2013
(Mboe)
    Total BOE
as at December 31, 2012
(Mboe)
      W.I.
Gross
    Co.Share
Gross
    Net     W.I.
Gross
    Co.Share
Gross
    Net
Proved Developed Producing     3,715     3,949     3,214     2,076     2,381     2,042
Proved Developed Non-Producing     552     563     499     433     443     386
Proved Undeveloped     4,610     4,929     4,215     4,039     4,338     3,765
Total Proved     8,877     9,441     7,928     6,548     7,163     6,193
Probable     7,738     8,023     6,831     5,058     5,356     4,473
Total Proved Plus Probable     16,615     17,464     14,759     11,606     12,518     10,667

Notes to table:
(1) Total values may not add due to rounding.
(2) BOEs are derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl).
(3) "Working Interest Gross" reserves are the Company's working interest (operating or non-operating) share before deducting royalty obligations and without including any royalty interests of the Company.
(4)  "Company Share Gross" reserves are the Company's working interest (operating or non-operating) share and before deducting royalty obligations but including any royalty interests of the Company.
(5) "Net" Reserves are the Company's working interest (operating or non-operating) share after deduction of royalty obligations plus any royalty interests of the Company.
   

Summary of Net Present Values of Future Net Revenue (Before Tax)

   (based on forecast price and costs)

      As At December 31, 2013(2)     As At
December 31,
2012 (3)
Reserves Category     0.0%
(M$)
    5.0%
(M$)
    10.0%
(M$)
    10%
(M$)
 
Proved Developed Producing     112,355     92,026     78,259     45,271  
Proved Developed Non-Producing     19,832     16,499     14,239     4,992  
Proved Undeveloped     105,640     75,062     54,859     49,387  
Total Proved     237,827     183,587     147,357     99,650  
Probable     257,412     156,838     103,791     67,357  
Total Proved Plus Probable     495,239     340,425     251,148     167,381  

Notes to table:
(1) Total values may not add due to rounding.
(2) Forecast pricing used is based on AJM Deloitte published price forecasts effective December 31, 2013.
(3) Forecast pricing used is based on AJM Deloitte published price forecasts effective December 31, 2012.
(4) Cash flows include the effects of the current Alberta Royalty Framework. The estimated future net reserves are stated before deducting future estimated site restoration costs and are reduced for future abandonment costs and estimated capital for future development associated with the reserves.
(5)  It should not be assumed that the net present values of future net revenues estimated by AJM Deloitte represent fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material.
   
Reserve Definitions:
(a)  "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(b) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(c) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
(d) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(e) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
(f) "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.
(g) The Net Present Value (NPV) is based on AJM Deloitte Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the AJM Deloitte evaluations will be attained, and variances could be material.
   

Finding and Development Costs ("F&D")

Yangarra's F&D costs for 2013, 2012 and the three year average are presented in the tables below. The costs used in the F&D calculation are the capital costs related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties.  Due to the timing of capital costs and the subjectivity in the estimation of future costs, 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 reserve additions for that year. The reserves used in this calculation are Company net reserve additions, including revisions.

Proved Finding & Development Costs ($ millions)

      2013     2012     2011 - 2013
Capital expenditures     47.0     19.8     130.8
Change in future capital     7.2     23.8     41.3
Total capital for F&D     54.2     43.6     172.1
                   
Reserve additions, net production (Mboe)     3,083     2,409     8,005
                   
Proved F&D costs - including future capital ($/boe)     17.58     18.09     21.50
Proved F&D costs - excluding future capital ($/boe)     15.25     8.22     15.85
                   
Proved Recycle Ratio                  
  Including future capital     2.06     1.41      
  Excluding future capital     2.37     3.10      
                     
                     
                   
Proved plus Probable Finding & Development Costs ($ millions)                  
      2013     2012     2011 - 2013
Capital expenditures     47.0     19.8     130.8
Change in future capital     33.9     35.7     78.3
Total capital for F&D     80.9     55.5     209.1
                   
Reserve additions, net production (Mboe)     5,750     4,459     13,141
                   
Proved plus Probable F&D costs - including future capital ($/boe)     14.07     12.45     15.91
Proved plus Probable F&D costs - excluding future capital ($/boe)     8.18     4.44     9.96
                   
Proved plus Probable Recycle Ratio                  
  Including future capital     2.57     2.05      
  Excluding future capital     4.42     5.74      
                   
                   

Net Asset Value ("NAV")

As at December 31, 2013   ($ millions)            
             
Present Value of Proved plus Probable Reserves, before tax (discounted at 10%)       $   251.1
Total Debt           (44.6)
             
Net Asset Value       $   206.5
             
Common shares outstanding at year end           147.1
             
Net asset value per share       $   1.40

Notes to tables:
(1)  The preceding table shows what is customarily referred to as a "produce out" net asset value calculation under which the current value of Yangarra's reserves would be produced at the AJM Deloitte forecast future prices and costs.  The value is a snapshot in time as at December 31, 2013 and is based on various assumptions including commodity prices and foreign exchange rates that vary over time.  In this analysis, the present value of the proved and probable reserves is calculated at a before tax 10 percent discount rate.
(2)  The 2013 total debt, excludes non-cash items (MTM on commodity contracts and flow through share obligations).
   

Advance Notice Bylaw

Yangarra is announcing that its Board of Directors approved the adoption of an advance notice by-law (the "Advance Notice By-law"). Among other things, the Advance Notice By-law fixes a deadline by which shareholders must submit a notice of director nominations to Yangarra prior to any annual or special meeting of shareholders where directors are to be elected and sets forth the information that a shareholder must include in the notice for it to be valid.

The Advance Notice By-law is similar to the advance notice requirements adopted by many other Canadian public companies. Specifically, the Advance Notice By-law requires advance notice to the Corporation in circumstances where nominations of persons for election as a director of Yangarra are made by shareholders other than pursuant to (i) a requisition of a meeting made pursuant to the provisions of the Business Corporations Act (Alberta) (the "Act"), or (ii) a shareholder proposal made in accordance with the provisions of the Act.

In the case of an annual meeting of shareholders, notice to the Corporation must be given not less than 30 or more than 65 days prior to the date of the annual meeting. In the event that the annual meeting is to be held on a date that is less than 50 days after the date on which the first public announcement of the date of the annual meeting was made, notice may be given not later than the close of business on the 10th day following such public announcement.

In the case of a special meeting of shareholders (which is not also an annual meeting), notice to the Corporation must be given not later than the close of business on the 15th day following the day on which the first public announcement of the date of the special meeting was made.

The Advance Notice By-law is effective immediately. At the next meeting of shareholders of the Corporation, shareholders will be asked to confirm and ratify the Advance Notice By-law. The full text of the Advance Notice By-law is available under Yangarra's profile at www.sedar.com.

Annual General Meeting of Shareholders

The Company's Annual General and Special Meeting of Shareholders is scheduled for 10:00 AM on Tuesday May 27, 2014 in the Tillyard Management Conference Centre, Main Floor, 715 5th Avenue SW, Calgary, AB.

Year End Disclosure

The Company's Annual Report (financial statements, notes to the financial statements and management's discussion and analysis) will be filed on SEDAR (www.sedar.com) and be available on the Company's website (www.yangarra.ca).

Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form which will be filed on SEDAR by April 30, 2014.

Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated.  The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe).  One ("BCF") equals one billion cubic feet of natural gas.  One ("Mmcf") equals one million cubic feet of natural gas.

Certain information regarding Yangarra set forth in this news release, including management's assessment of future plans, operations and operational results may constitute forward-looking statements under applicable securities law and necessarily involve risks associated with oil and gas exploration, production, marketing and transportation such as loss of market, volatility of prices, currency fluctuations, imprecision of reserves estimates, environmental risks, competition from other producers and ability to access sufficient capital from internal and external sources.  As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

The initial production rates discussed in this press release are not necessarily indicative of long-term performance or of ultimate recovery due to high initial decline rates.

All reference to $ (funds) are in Canadian dollars.

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

SOURCE Yangarra Resources Ltd.

Image with caption: "1) Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves. 2) Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure) (CNW Group/Yangarra Resources Ltd.)". Image available at: http://photos.newswire.ca/images/download/20140325_C6908_PHOTO_EN_38294.jpg

For further information:

please contact James Evaskevich, President and CEO, at (403) 262-9558