Hemisphere Energy Increases Proved Plus Probable Reserve Value by 77% to $116.6 million (discounted at 10%), and Net Asset Value by 68% to $1.12 per share

March 20, 2018

Vancouver, British Columbia, March 20, 2018 – Hemisphere Energy Corporation (TSX-V: HME) ("Hemisphere" or the "Company") is pleased to announce highlights from its independent reserves evaluation effective as at December 31, 2017 prepared by McDaniel & Associates Consultants Ltd. ("McDaniel").

In September 2017, Hemisphere entered into a five-year term loan with a borrowing base of up to US$35.0 million. This has allowed Hemisphere to actively move forward with development of its Atlee Buffalo assets in the Upper Mannville F and G pools. During 2017, Hemisphere spent $8.3 million which included capital to drill six wells, expand its F pool facility, and construct a new facility for G pool production. Reserve growth through 2017 is a direct result of the recognized waterflood success in Atlee Buffalo, with Hemisphere's Proved reserve volumes exceeding Hemisphere's year-end 2016 Proved plus Probable reserve volumes.

2017 Reserve Highlights

Proved plus Probable Reserves ("2P")

  • Increased net present value of future net revenue, discounted at 10%, before tax ("NPV10 BT") by 77% to $116.6 million.
  • Increased reserve volumes by 57% to 7.2 MMboe (97% oil).
  • Replaced 1,185% of estimated 2017 production.
  • Added 2.9 Mboe of reserve volumes, at a finding and development cost  ("F&D cost") of $7.25/boe (including changes in future development capital ("FDC")), for a recycle ratio of 2.8.
  • Achieved a two-year average F&D cost of $7.54/boe (including changes in FDC) for a recycle ratio of 2.2.
  • Increased NPV10 BT per basic share by 69% to $1.30.
  • Improved net asset value ("NAV") by 68% to $1.12 per basic share.
  • Increased reserve life index ("RLI") by 26% to 29.8 years based on estimated 2017 average production, representing a low decline, long life asset base in early stages of development.

Proved Reserves ("1P")

  • Increased NPV10 BT by 76% to $80.4 million.
  • Increased reserve volumes by 57% to 4.9 Mboe (97% oil).
  • Replaced 841% of estimated 2017 production.
  • Added 2.0 Mboe of reserve volumes, at an F&D cost of $8.93/boe (including changes in FDC), for a recycle ratio of 2.3.
  • Achieved a two-year average F&D cost of $9.22/boe (including changes in FDC) for a recycle ratio of 1.8.
  • Increased NPV10 BT per basic share by 70% to $0.90.
  • Improved NAV by 67% to $0.71 per basic share.
  • Increased RLI by 26% to 20.5 years.

The reserves data set forth below is based upon an independent reserves evaluation prepared by McDaniel dated March 9, 2018 with an effective date of December 31, 2017 and is 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"). Additional reserve information as required under NI 51-101 will be included in Hemisphere's Annual Information Form which will be filed on SEDAR on or before April 30, 2018.  Due to rounding, certain totals in the columns may not add in the following tables.  All dollar values are in Canadian dollars, unless otherwise noted.

Summary of Reserves(1)

 

 

Heavy Oil

Conventional

Natural Gas

 

Total

Reserves Category

(Mbbl)

(MMcf)

(Mboe)

Proved

 

 

 

  Developed Producing

1,770.9

690.7

1,886.0

  Developed Non-Producing

374.0

117.7

393.7

  Undeveloped

2,617.8

151.6

2,643.1

Total Proved

4,762.7

960.0

4,922.7

Probable

2,186.8

391.9

2,252.1

Total Proved plus Probable

6,949.5

1,351.9

7,174.8

Note:

  1. Reserves are presented as "gross reserves" which are the Company's working interest reserves before royalty deductions and without including any royalty interests.

Summary of Net Present Value of Future Net Revenue(1)(2)

 

Net Present Value of Future Net Revenue, Before Tax

(M$, except per share amount)

 

Discounted at (% per Year)

Reserves Category

0%

5%

10%

Proved

 

 

 

  Developed Producing

48,757.8

40,432.3

34,372.3

  Developed Non-Producing

9,175.5

7,498.8

6,256.0

  Undeveloped

64,476.9

50,330.5

39,791.1

Total Proved

122,410.2

98,261.6

80,419.4

Probable

73,503.4

50,231.5

36,253.8

Total Proved plus Probable

195,913.5

148,493.1

116,673.2

Per basic share(3)

 

 

 

  Proved

$1.36

$1.09

$0.90

  Proved plus Probable

$2.18

$1.65

$1.30

Notes:

  1. Based on McDaniel January 1, 2018 forecast prices.
  2. The net present value of future net revenue does not represent the fair market value of Hemisphere's reserves.
  3. Based on there being 89,793,302 issued and outstanding shares of the Company as of December 31, 2017.

 

Future Development Costs ("FDC")

The following summarizes the development costs deducted in the estimation of the net present value of the future net revenue attributable to 1P and 2P reserves (using forecast prices and costs only).

 

Forecast Prices and Costs

 

 

Year

 

Proved

 (M$)

Proved plus Probable

(M$)

2018

13,604

17,304

2019

13,706

14,516

2020

1,590

2,605

Total Undiscounted

28,900

34,424

Total Discounted at 10%

26,030

30,984

 

2017 Finding and Development Costs and Recycle Ratios(1)(2)

 

2017

2017 and 2016

2-Year Average

 

 

Proved 

Proved plus Probable

 

Proved  

Proved plus Probable

F&D Costs(3)

 

 

 

 

   Exploration and development capital (M$)(4)(5)

  8,285.0

  8,285.0

10,716.3

10,716.3

   Total change in FDC (M$)

  9,775.6

12,374.4

12,310.0

16,160.0

Total F&D capital, including change in FDC (M$)

18,060.6

20,659.4

23,026.3

26,876.3

Reserve additions, including revisions (Mboe)

  2,022.2

  2,851.1

  2,498.2

  3,566.7

F&D costs, including FDC ($/boe)

8.93

7.25

9.22

7.54

Recycle Ratio(6)

2.3

2.8

1.8

2.2

Notes:

  1. All financial information included in this news release is per Hemisphere's preliminary unaudited financial statements for the year ended December 31, 2017 which have not yet been approved by the Company's audit committee or board of directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere's financial statements for the year ended December 31, 2017 and the review and approval of same with the Company's audit committee and board of directors.
  2. See "Oil and Gas Advisories" and "Oil and Gas Metrics".
  3. F&D costs are calculated as the sum of development capital plus the change in future development capital for the period divided by the change in reserves that are characterized as development for the period. Finding and development costs take into account reserves revisions during the year on a per boe basis.
  4. The aggregate of the exploration and development costs incurred in the 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.
  5. The capital expenditures also exclude capitalized administration costs. 
  6. Recycle ratio is calculated as operating netback divided by F&D costs. Operating netback is calculated as the operating field netback plus the Companys realized commodity hedging gain (loss) per barrel of oil equivalent.  Operating field netback is calculated as the Company’s oil and gas sales, less royalties, operating expenses and transportation costs per barrel of oil equivalent. The Company's estimated operating netback in 2017 was $20.42/boe (unaudited) and the combined two-year average for 2017 and 2016 was $16.77/boe (unaudited).

 

Summary of McDaniel Pricing as of January 1, 2018

The following table is McDaniel's forecast pricing and foreign exchange rates as at January 1, 2018 which were used in the preparation of McDaniel's reserve evaluation. Overall, McDaniel's forecast of WTI and WCS pricing is down an average of approximately 6% and 7%, respectively, from the January 1, 2017 outlook over the same 15 year period.

 

 

Oil

Natural Gas

 

 

 

 

 

Year

 

 

WTI

Crude Oil

 

Edmonton

Light Crude Oil

Western Canadian Select

Crude Oil

 

Alberta

AECO Spot

Price

 

 

 

Inflation

 

US/Cdn

Exchange

Rate

 

($US/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/MMBtu)

(%)

($US/$Cdn)

2018

58.50

70.10

51.90

2.25

0

0.790

2019

58.70

71.30

57.00

2.65

2.0

0.790

2020

62.40

74.90

61.40

3.05

2.0

0.800

2021

69.00

80.50

66.00

3.40

2.0

0.825

2022

73.10

82.80

67.90

3.60

2.0

0.850

2023

74.50

84.40

69.20

3.65

2.0

0.850

2024

76.00

86.10

70.60

3.75

2.0

0.850

2025

77.50

87.80

72.00

3.80

2.0

0.850

2026

79.10

89.60

73.50

3.90

2.0

0.850

2027

80.70

91.40

74.90

3.95

2.0

0.850

2028

82.30

93.20

76.40

4.05

2.0

0.850

2029

83.90

95.00

77.90

4.15

2.0

0.850

2030

85.60

97.00

79.50

4.25

2.0

0.850

2031

87.30

98.90

81.10

4.30

2.0

0.850

2032

89.10

100.90

82.70

4.35

2.0

0.850

Thereafter

Escalation Rate of 2%/year

2.0

0.850

 

 

Reserve Life Index ("RLI")

 

As at December 31

  2017(1)

  2016(2)

Proved Developed Producing

  7.8

  8.9

Proved

20.5

16.3

Proved plus Probable

29.8

23.7

Notes:

  1. Calculated as the applicable reserves volume divided by Hemisphere's estimated 2017 average production of 659 boe/d.
  2. Calculated as the applicable reserves volume divided by Hemisphere's 2016 average production of 527 boe/d.

 

 

 

Net Asset Value ("NAV")(1)

 

 

As at December 31

 

2017

2016

 

(M$ except share amounts)

 

Proved 

Proved plus Probable

 

Proved  

Proved plus Probable

NPV10 BT

80,419

116,673

45,681

65,902

Undeveloped Land & Seismic

   2,287(2)

  2,850(3)

Net Debt

 (18,598)(4)

(11,827)

Shares Outstanding (basic)

89,793,302

85,745,102

Net Asset Value per share (basic)

$0.71

$1.12

$0.43

$0.67

Notes:

  1. Based on McDaniel January 1, 2018 forecast pricing.
  2. Based on an internal evaluation by management of Hemisphere as of December 31, 2017 with an average value of $50 per acre for 34,703 undeveloped net acres, and $0.55 MM for seismic.
  3. Based on an internal evaluation by management of Hemisphere as of December 31, 2016 with an average value of $50 per acre for 46,000 undeveloped net acres, and $0.55 MM for seismic.
  4. All financial information as at December 31, 2017 is per Hemisphere's preliminary unaudited financial statements for the year ended December 31, 2017 which has not yet been approved by the Company's audit committee or board of directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to changes as a result of the completion of the independent audit on Hemisphere's financial statements for the year ended December 31, 2017 and the review and approval of same with the Company's audit committee and board of directors.

 

Corporate Outlook

Additions to the Company's reserves were achieved in 2017 due to significant development activity in the Atlee Buffalo area leading to further recognition of successful waterflood response in both the Atlee Buffalo Upper Mannville F and G pools. Of the 66 MMbbl OOIP mapped by McDaniel across both of these pools, overall aggregate recovery factors of 10% (1P) to 12% (2P) are reflected in McDaniel’s reserve report as at December 31, 2017. Last year, as at December 31, 2016,  recovery factors of just 7% (1P) to 8% (2P) were reflected in McDaniel’s reserve report. Based on analysis of analogue performance in combination with internal reservoir simulation models, management anticipates significant potential for Hemisphere to achieve greater ultimate recovery factors than those currently booked in both Atlee Buffalo pools.

  • Analogues to Hemisphere’s Atlee Buffalo pools include the nearby Upper Mannville N2N and YYY pools. These pools have been producing under waterflood since the late 1990’s and have already recovered 14% and 23%, respectively, of Alberta Energy mapped oil in place. After 20 years of waterflood, these pools produced through the fourth quarter of 2017 at approximately 66% and 35% of peak pool oil rates, respectively, and have maintained relatively flat production over the past five years. Management expects these analogue pools to reach recovery factors much higher than those already attained.
  • Reserves have been booked in the Atlee Buffalo F pool at a total pool recovery factor of approximately 12% (1P) to 15% (2P) of McDaniel's mapped 28 MMbbl OOIP. There are currently nine total producing wells in the pool, including two producers drilled in 2017.
  • Reserves have been booked in the Atlee Buffalo G pool at a total pool recovery factor of approximately 8% (1P) to 10% (2P) of McDaniel's mapped 38 MMbbl OOIP. There are currently two producing wells in the pool, including one producer drilled in 2017.
  • 18 Proved and four Probable Atlee Buffalo drilling locations have been attributed reserves in McDaniel’s reserve report as at December 31, 2017.

In 2018, Hemisphere has already drilled three wells and is preparing for a significant drilling program through the remainder of the year in order to build on the momentum of recent production, injection, and facility additions across both Atlee Buffalo pools. Horizontal drilling, slotted liners, and waterflood has proved to be successful in these pools to date, and the Company expects to see meaningful growth in production and reserves through the year with continued development of its core properties.

 

About Hemisphere Energy Corporation

Hemisphere Energy Corporation is a producing oil and gas company focused on developing conventional oil assets with low risk drilling opportunities. Hemisphere plans continual growth in production, reserves, and cash flow by focusing on existing assets with significant growth potential and executing strategic acquisitions.  Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol "HME".

For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:

Don Simmons, President & Chief Executive Officer

Telephone: (604) 685-9255
Email: info@hemisphereenergy.ca

Scott Koyich, Investor Relations
Telephone: (403) 619-2200
Email: scott@briscocapital.com
Website: www.hemisphereenergy.ca

Forward-looking Statements

This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the volumes of Hemisphere's oil and gas reserves and the estimated net present values of the future net revenues of such reserves; Hemisphere's estimated 2017 average corporate production rate; the anticipation by Hemisphere for the recovery factors for the N2N and YYY pools reaching recovery factors that are higher than currently estimated; the anticipation that there is significant potential for Hemisphere to achieve greater ultimate recovery factors than those currently booked in both Atlee Buffalo pools; Hemisphere's expectation that it will see meaningful growth in production and reserves through the year with continued development of its core properties; and the Company's anticipated filing date for its annual information form for the year ending December 31, 2017.

The estimates of Hemisphere's reserves and the recovery factors  provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Hemisphere which have been used to develop such statements and information but which may prove to be incorrect. Although Hemisphere 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 Hemisphere can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that Hemisphere will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities are consistent with past operations; the quality of the reservoirs in which Hemisphere operates and continued performance from existing wells; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Hemisphere's reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Hemisphere's current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Hemisphere operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Hemisphere to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Hemisphere has an interest in to operate the field in a safe, efficient and effective manner; the ability of Hemisphere 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 and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Hemisphere to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Hemisphere operates; and the ability of Hemisphere to successfully market its oil and natural gas products.

The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of Hemisphere's products, the early stage of development of some of the evaluated areas and zones; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Hemisphere or by third party operators of Hemisphere's properties, increased debt levels or debt service requirements; inaccurate estimation of Hemisphere's oil and gas reserve volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Hemisphere's public disclosure documents, (including, without limitation, those risks identified in this news release and in Hemisphere's annual information form).

The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Hemisphere does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Oil and Gas Advisories

All reserve references in this news release are "gross" or "Company interest reserves". Such reserves are the Company's total working interest reserves before the deduction of any royalties and without including any royalty interests of the Company.  As of December 31, 2017, the Company did not have any royalty interests.

It should not be assumed that the net present value of the estimated net revenues presented in this news release represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Hemisphere'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.

All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses. Future net revenues have been presented in this news release on a before tax basis.

"Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe's 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. In addition, 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.

Original Oil In Place ("OOIP") is used by Hemisphere in this news release as an equivalent to Discovered Petroleum Initially-In-Place ("DPIIP"). DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves and contingent resources; the remaining portion of DPIIP is unrecoverable.  The OOIP/DPIIP set forth in this news release has been provided for the sole purpose of highlighting the recovery factors used by Hemisphere's independent engineers in attributing reserves to Hemisphere effective as of December 31, 2017.  It should not be assumed that any portion of the OOIP/DPIIP set forth in the news release is recoverable other than the portion which has been attributed reserves by Hemisphere's independent engineers.  There is uncertainty that it will be commercially viable to produce any portion of the OOIP/DPIIP other than the portion that is attributed reserves.

Analogous Information

The information concerning Upper Mannville N2N and YYY analogue pools may be considered to be "analogous information" within the meaning of applicable securities laws.  Such information was obtained by Hemisphere management throughout the year ended December 31, 2017 from various public sources including information available to Hemisphere through AccuMap.  Management believes such information is analogous to the Atlee Buffalo Upper Mannville F and G pools in which Hemisphere has an interest and is relevant as it may help to demonstrate the reaction of such pools to waterflood stimulations.  Hemisphere is unable to confirm whether the analogous information was prepared by a qualified reserves evaluator or auditor or in accordance with the COGE Handbook and therefore, the reader is cautioned that the data relied upon by Hemisphere may be in error and/or may not be analogous to the oil pools in which Hemisphere holds an interest.

Oil and Gas Metrics

This news release contains metrics commonly used in the oil and natural gas industry, such as finding and development ("F&D") costs", "recycle ratio", "operating netback", " and "reserve life index ("RLI")".  These terms do not have a standardized meaning and the Company's calculation of such metrics may not be comparable to the calculation method used or presented by other companies for the same or similar metrics, and therefore should not be used to make such comparisons.

"Finding and development costs" or "F&D costs" are calculated as the sum of development capital plus the change in future development capital ("FDC") for the period divided by the change in reserves that are characterized as development for the period. Finding and development costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

"Development capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development.  Development capital excludes capitalized administration costs.

"Recycle ratio" is calculated as the operating netback divided by the F&D cost per boe for the year.

"Reserve life index" is calculated as total company interest reserves divided by annual production, for the year indicated.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

Drilling Locations

This news release discloses drilling locations in two categories: (i) proved locations; (ii) probable locations. Proved locations and probable locations, which are sometimes collectively referred to as “booked locations”, are derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel and effective as of December 31, 2017 and account for drilling locations that have associated proved or probable reserves, as applicable.  The drilling locations on which the Company actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Financial Information

All financial information included in this news release is per Hemisphere's preliminary unaudited financial statements for the year ended December 31, 2017 which have not yet been approved by the Company's audit committee or board of directors and therefore represents management's estimates.  Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere's financial statements for the year ended December 31, 2017  and the review and approval of same with the Company's audit committee and board of directors.  All amounts are expressed in Canadian dollars unless otherwise noted.

Non-IFRS Measures

The news release contains terms commonly used in the oil and gas industry which are not defined by or calculated in accordance with International Financial Reporting Standards ("IFRS"), such as: (i) net debt; and (ii) operating netback, operating netback per boe and operating field netback.  These terms should not be considered an alternative to, or more meaningful than the comparable IFRS measures (as determined in accordance with IFRS) which in the case of operating field netback and operating netback, are cash flow from operating activities and net income or net loss, respectively.  There is no IFRS measure that is reasonably comparable to net debt.  These measures are commonly used in the oil and gas industry and by Hemisphere to provide shareholders and potential investors with additional information regarding: (i)in the case of operating netback, operating netback per boe and operating field netback, the indication of the Company's profitability relative to current commodity prices; and (ii) in the case of net debt, the capital structure and financial position of the Company.  

Hemisphere's determination of these measures may not be comparable to that reported by other companies.  Net debt is calculated as the total of the Company’s bank debt and current liabilities, less current assets.  Operating netback is calculated as the operating field netback plus the Company’s realized commodity hedging gain (loss) per barrel of oil equivalent.  Operating netback per boe is calculated as operating netback divided by the applicable barrels of oil equivalent of production.  Operating field netback is calculated as the Company’s oil and gas sales, less royalties, operating expenses and transportation costs.  The Company has provided additional information on how these measures are calculated in the Management’s Discussion and Analysis for the year ended December 31, 2016 and for the three and nine month period ended September 30, 2017, which are available under the Company’s SEDAR profile at www.sedar.com.

 

Definitions and Abbreviations

bbl

barrel

$US

United States dollar

Mbbl

thousands of barrels

$Cdn

Canadian dollar

MMbbl

millions of barrels

M$

thousand dollars

boe

barrel of oil equivalent

MM

million

boe/d

barrel of oil equivalent per day

NPV10 BT

Net Present Value of future net revenue, discounted at 10%, before tax

Mboe

thousands of barrels of oil equivalent

WTI

West Texas Intermediate

MMboe

millions of barrels of oil equivalent

WCS

Western Canadian Select

MMcf

million cubic feet

AECO

Alberta Energy Company

MMbtu

million British Thermal Unit

FDC

Future Development Costs

 

 

F&D

Finding and Development Costs

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 news release.