Yangarra Announces 2016 Year End Corporate Reserves Information

CALGARY, Feb. 14, 2017 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX:YGR) releases the results of its 2016 year end oil and gas reserves evaluation.

Reserve Report Highlights:

The independent reserves report prepared by Deloitte is dated February 14, 2017 and is effective as of December 31, 2016, ("2016 Reserve Report").

The financial and operational information below is based on estimates and are unaudited.

Proved Developed producing reserves ("PDP")

  • 7.9 million boe
  • Net present value before tax discounted at 10% ("NPV10") of $139.1 million
  • Finding and development costs of $9.41/boe resulting in a PDP recycle ratio of 2.4 times
  • PDP net asset value per fully diluted ("FD") common share ("NAV per FD Share") of $0.96 (PDP NPV10 less estimated year end debt with no value included for undeveloped land)

Total Proved reserves ("1P")

  • 36.5 million boe
  • NPV10 of $489.6 million
  • Finding and development costs including changes in future development capital ("FDC") of $6.75/boe resulting in a recycle ratio of 3.4 times
  • 1P NAV per FD Share of $5.01 (1P NPV10 less estimated year end debt with no value included for undeveloped land)

Proved plus probable reserves ("2P")

  • 60.6 million boe
  • NPV10 of $734.5 million
  • Finding and development costs including changes in FDC of $6.18/boe resulting in a recycle ratio of 3.7 times
  • 2P NAV per FD Share of $7.84 (2P NPV10 less estimated year end debt with no value included for undeveloped land)

Other Information

  • 2016 field operating netbacks used to calculate recycle ratios was $22.83/boe
  • 2P Future development costs of $366.2 million, which is a 37% increase from 2015
  • 2P Reserve Life Index ("RLI") based on current production of 36.9 years, 1% decrease from 2015
  • 359 Mbbl of negative technical revisions to PDP oil wells primarily associated with performance of legacy wells completed with ball-drop completion systems
  • The increase in the PUD and Probable locations is a result of a drilling program that focused on developing new land with one well on a drilling pad, which allows for 4-5 follow-up wells per drilling pad without any additional infrastructure

Operations update

Yangarra's 10 well Cardium drilling program commenced in Q3 2016 and is anticipated to be complete by the end of Q1 2017. All of the wells except well #2 were drilled into the lower bioturbated portion of the Cardium reservoir with 8 of the 10 wells drilled with 2 mile lateral sections and 2 wells drilled with 1.5 mile lateral sections. Early indications suggest the 2 mile wells are the optimum lateral length, however specialized casing and float equipment is required to land the casing to drilled depth.

Pressure data obtained during fracking operations confirms that both frack intensity of 50-55 stages per mile and 100-meter inter-well spacing do not show communication.   Frack operations in the bioturbated section require high pressure frack and coil spreads to crack the rock given the higher frack pressures encountered.

Initial production rates from wells 1 through 4 were previously press released by the Company on January 24, 2017, wells 5 and 6 have also been placed on-stream with both wells exceeding expectations. Wells 7 and 8 are currently being completed and wells 9 and 10 are currently drilling with 2 drilling rigs working. Yangarra expects to have all the wells completed and tied in by the end of Q1 2017.

Current corporate production is approximately 4,500 boe/d.

Oil and Gas Reserves

The following tables summarize certain information contained in the 2016 Reserve Report. The 2016 Reserve Report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101").

Deloitte is using a price forecast of US$55.00/bbl WTI and US$57.00/bbl WTI for light oil for 2017 and 2018, respectively, and $3.25/mcf and $3.35/mcf for AECO natural gas in 2017 and 2018, respectively.

Summary of Oil and Gas Reserves
(Company Share Gross volumes based on forecast price and costs)

Reserves Category





Light and
Medium Oil
(Mbbl)

Natural Gas
Liquids
(Mbbl)

Natural
Gas
(MMcf)

Total BOE
2016
(Mboe)


Total BOE
2015
(Mboe)

Proved Developed Producing

1,773

1,641

26,628

7,851


5,626

Proved Developed Non-Producing

171

76

2,362

641


531

Proved Undeveloped

8,062

5,378

87,171

27,969


18,555

Total Proved

10,007

7,095

116,161

36,462


24,712

Probable

6,124

4,885

79,015

24,178


15,895

Total Proved Plus Probable

16,130

11,980

195,176

60,640


40,607

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)

"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.

Summary of Net Present Values of Future Net Revenue (Before Tax)
(based on forecast price and costs)


As At December 31, 2016(2)


As At
December 31,
2015 (3)

Reserves Category

0.0%

(M$)

5.0%

(M$)

10.0%

(M$)

15.0%

(M$)

20.0%

(M$)


10%

(M$)

Proved Developed Producing

207,669

166,149

139,094

120,316

106,608


97,909

Proved Developed Non-Producing

13,147

10,509

8,734

7,467

6,518


5,941

Proved Undeveloped

669,110

466,334

341,751

259,653

202,514


212,040

Total Proved

889,925

642,991

489,580

387,436

315,639


315,890

Probable

720,453

395,769

244,894

164,337

116,574


183,590

Total Proved Plus Probable

1,610,378

1,038,760

734,474

551,773

432,213


499,480

Notes to table:





(1)

Total values may not add due to rounding.


(2)

Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2016.


(3)

Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2015.


(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)

Net present values of future net revenues estimated by Deloitte does not 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 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 Deloitte evaluations will be attained, and variances could be material.

Finding and Development Costs ("F&D")

Yangarra's F&D costs for 2016, 2015 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)


2016

2015

2014 - 2016

Capital expenditures

31.0

42.0

151.0

Change in future capital

55.6

(7.2)

182.0

Total capital for F&D

86.6

34.8

333.0





Reserve additions, net production (Mboe)

12,819

5,123

30,025





Proved F&D costs – including future capital ($/boe)

6.75

6.79

11.09

Proved F&D costs – excluding future capital ($/boe)

2.42

8.20

5.03





Proved Recycle Ratio





Including future capital               

3.38

2.69



Excluding future capital

9.44

2.23


Proved plus Probable Finding & Development Costs ($ millions)


2016

2015

2014 - 2016

Capital expenditures

31.0

42.0

151.0

Change in future capital

99.4

(30.5)

241.4

Total capital for F&D

130.4

11.5

392.4





Reserve additions, net production (Mboe)

21,102

4,048

46,180





Proved plus Probable F&D costs – including future capital ($/boe)

6.18

2.83

8.50

Proved plus Probable F&D costs – excluding future capital ($/boe)

1.47

10.38

3.27





Proved plus Probable Recycle Ratio





Including future capital          

3.70

6.45



Excluding future capital

15.54

1.76


Net Asset Value ("NAV")

As at December 31, 2016  

PDP

Total
Proved

Proved +
Probable





Present Value Reserves, before tax (discounted at 10%) ($ million)

$139.1

$489.6

$734.5

Total Net Debt ($ million) (unaudited)

(65.0)

(65.0)

(65.0)

Proceeds from the exercise of options (2)

9.0

9.0

9.0

Net Asset Value

$83.1

$433.6

$678.5





Fully diluted common shares outstanding (million)

86.6

86.6

86.6

Net asset value per share

$0.96

$5.01

$7.84

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 Deloitte forecast future prices and costs.  The value is a snapshot in time as at December 31, 2016 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 calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are "in-the-money" based on the closing price of YGR of $1.92 and $0.55 per common share respectively, as at December 31, 2016 and 2015. There were no "in-the-money" stock options at December 31, 2015.   

Year End Disclosure

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 March 31, 2017.

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 nor its Regulation Service Provider (as that term is defined in the Policies of the TSX) accepts responsibility for the adequacy and accuracy of this release.  

SOURCE Yangarra Resources Ltd.

For further information: please contact Jim Evaskevich, President and CEO, at (403) 262-9558


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