Raging River Exploration Inc. Announces Preliminary 2017 Results, 2017 Year End Reserves and Operations Update

^{Notes:
(1)      See “Barrels of Oil Equivalent”
(2)      See “Non IFRS Measures”}

Operations Update

Fourth quarter 2017 production averaged approximately 23,670 boe/d (93% oil), bringing average 2017 annual production to 22,850 boe/d (92% oil) representing year over year production per share growth of 25%.

The $372.1 million of capital resulted in 337.8 net Viking wells and 1 net Duvernay well.  This included 363 (322.8 net) crude oil wells, 9 (9.0 net) injection wells and 7 (7.0 net) dry holes. In addition to the drilling capital, a total of $33.8 million was spent on land primarily in the east Duvernay shale basin.

For 2018, quarter to date, we have drilled approximately 72 net wells of the 111 net wells budgeted for the first quarter of 2018.  Field conditions and access to services have been supportive and as a result, we anticipate completing all drilling and completion operations by early March. Total capital expenditures for the first quarter are expected to be approximately $110 million, allocated to 108 net Viking wells and 3 net Duvernay wells.

Duvernay Update

Our initial Duvernay light oil discovery well (4-11) in the Ferrybank area of central Alberta continues to produce at strong rates. The well has now been on production for approximately 100 days with a few intermittent shut-in periods for equipping and pump maintenance with cumulative oil production to date of 19,000 bbls.  As anticipated, the well continues to produce at a very low gas oil ratio of 250-300 scf/bbl.

Continued geotechnical success has been observed throughout the first quarter.  Our second well in the Ferrybank area (2-32) was successfully drilled to a 2 mile lateral length with geotechnical results exceeding our expectations for the area.  Our third well in the Pembina (Pigeon Lake) area (14-36) was recently cored and is currently drilling its 1.5 mile lateral.  This well has also confirmed our geotechnical expectations of this area with estimated net pay in excess of 20m.  We anticipate drilling a fourth well in the Gilby area prior to break-up.  The first four evaluation wells are targeted to provide an initial evaluation across our 250,000 net acres in the play.

GLJ evaluated the reserves associated with the discovery well at 4-11 and assigned proved producing and proved plus probable producing gross reserves of 181 and 229 mboe, respectively (96% oil).  They also assigned 3.8 net undeveloped locations as a result of the success of 4-11 yielding total proved plus probable gross reserves assignments for Ferrybank of 1,151 mboe (95% oil).

2017 Corporate Reserves Highlights:

• Proven Developed Producing (“PDP”) reserves
  • Increased by 5% to 34.7 mmboe from 33 mmboe (93% oil).
  • Replaced production by 121%.
  • Excluding the capital associated with the Duvernay; finding and development (“F&D”) costs were $33.32 per boe resulting in a recycle ratio of 1.1 times
• Total Proven (“TP”) reserves
  • Increased 15% to 82 mmboe from 71.6 mmboe (94% oil).
  • Replaced production by 225%.
  • Excluding the capital associated with the Duvernay; F&D costs, including the change in FDC, were $26.69 per boe resulting in a recycle ratio of 1.4 times
• Proven plus Probable (“P+P”) reserves
  • Increased 14% to 106.7 mmboe from 94 mmboe (94% oil).
  • Replaced production by 252%.
  • Excluding the capital associated with the Duvernay; F&D costs, including the change in FDC, were $23.28 per boe resulting in a recycle ratio of 1.6 times
• Based on the net present value of future net revenues discounted at 10% (“PV10”) before taxes of our P+P reserves as presented in the Engineering Report, plus our internally estimated undeveloped land value of $237 million and net of estimated net debt of $299.6 million to the Company’s net asset value as at December 31, 2017 equates to $9.16 per common share, up from $8.35 as at December 31, 2016.

2017 Independent Reserves Evaluation:

The following summarizes certain information contained in the Engineering Report.  The Engineering Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE 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 the Company’s Annual Information Form which will be filed on SEDAR by the end of March 2018.

Corporate Reserves Information: 

Notes:

1. Oil” includes all light & heavy crude oil volumes, and natural gas liquids volumes. Of the total proven plus probable reserves volumes presented as “Oil” above, approximately 93% is light and medium crude oil, 6% is heavy crude oil and 1% is natural gas liquids volumes.
2. Reserves have been presented on gross basis which are the Company’s total working interest share before the deduction of any royalties and without including any royalty interests of the Company.
3. Based on Sproule’s December 31, 2017 escalated price forecast.
4. It should not be assumed that the present worth of estimated future net revenue presented in the tables above represents 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 reserves estimates of Raging River’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.
5. All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well and facility abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
6. Totals may not add due to rounding.
7. Pursuant to the COGE Handbook, reported reserves should target at least a 90 percent probability that the quantities actually recovered will be equal to or exceed the estimated proved reserves and that at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

Net Asset Value

Notes:

1. Evaluated by Sproule and GLJ as at December 31, 2017. Net present value of future net revenue does not represent fair market value of the reserves.
2. Net present values (“NPV”) equals net present value of future net revenue before taxes based on Sproule’s forecast prices and costs as of December 31, 2017.
3. Internally evaluated with an average value of $400 per acre for 592,003 undeveloped net acres.
4. Net debt as at December 31, 2017, including working capital deficit (unaudited).
5. Fully-diluted shares at December 31, 2017 total: including outstanding common shares of 231.3  million and 1.98 million stock options, restricted awards and performance awards that are in-the-money as at December 31, 2017
6. Per share figures based on fully-diluted shares outstanding as at December 31, 2017 – see note 5.

Future Development Costs

The following is a summary of the estimated FDC required to bring P+P undeveloped reserves on production.

Notes:

1. Financial and production information is per the Company’s 2017 preliminary unaudited financial statements and is therefore subject to audit.
2. Finding, development and acquisition (“FD&A“) costs are used as a measure of capital efficiency.  The calculation includes all capital costs, including capital spent on acquisitions, for that period plus the change in FDC for that period.  F&D as presented herein includes all capital costs, excluding capital spent on acquisitions, for that period plus the change in FDC for that period. This total capital including the change in the FDC is then divided by the change in reserves for that period incorporating all revisions and production for that same period.  For example: 2017 Total Proven = ($372,100,000+$167,823,000) / (81,998 mboe-71,577mboe +8,340mboe) = $28.78 per boe.  There was no acquisition capital for Raging River in 2017.
3. Recycle Ratio is calculated by dividing the operating netback per boe by the FD&A costs for that period.  For example: 2017 Total Proven = ($36.36/$28.78) = 1.3.  The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. 
4. The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year.  For example: 2017 Total Proven = (81,998 mboe -71,577 mboe +8,340 mboe)/8,340 mboe = 225%.
5. RLI is calculated by dividing the reserves in each category by the average annual production for that period.  For example 2017 Total Proven = (81,998 mboe) / (22,850 boe*.365) = 9.8 years.

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2017, reflected in the Sproule Report, used to estimate the reserves volumes and associated values in the Engineering Report.  These price assumptions were provided to Raging River by Sproule and were Sproule’s then current forecast at the date of the Sproule Report.

Thereafter                             Escalation rate of 2.0%

Notes:

1. This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
2. The exchange rate used to generate the benchmark reference prices in this table.
3. As at December 31, 2017.