CALGARY, ALBERTA–(Marketwired – Feb. 7, 2017) – Raging River Exploration Inc. (“Raging River” or the “Company“) (TSX:RRX) is pleased to present the results of the independent reserves report (the “Sproule Report”) prepared by Sproule Associates Ltd. (“Sproule”) as of December 31, 2016.
During 2016, the Company invested $403.5 million (unaudited) consisting of $192 million of acquisition capital and $211.5 million of development capital into the expansion and development of the Viking play. This invested capital resulted in estimated average annual production of 17,900 boe/d (92% oil) representing year over year production per debt adjusted share growth of 20%. 2016 Proved plus Probable Finding Development and Acquisition (“FD&A”) costs including changes in Future Development Capital (“FDC”) were $19.43 per boe resulting in a Proved plus Probable (“P+P”) recycle ratio of 1.5.
2016 Reserves Highlights:
- Proven Developed Producing (“PDP”) reserves
- Increased by 35% (24% per debt adjusted share) from 24.5 mmboe to 33 mmboe (92% oil).
- Replaced production by 229%.
- FD&A costs including the change in FDC of $26.88 per boe resulting in a recycle ratio of 1.1 times
- Total Proven (“TP”) reserves
- Increased 25% (15% per debt adjusted share) from 57.4 mmboe to 71.6 mmboe (94% oil).
- Replaced production by 317%.
- FD&A costs including the change in FDC of $23.55 per boe resulting in a recycle ratio of 1.3 times
- Proven plus Probable (“P+P”) reserves
- Increased 23% (13% per debt adjusted share) from 76.4 mmboe to 94 mmboe (94% oil).
- Replaced production by 369%.
- FD&A costs including the change in FDC of $19.43 per boe resulting in a recycle ratio of 1.5 times
- Using the independent reserves evaluation effective December 31, 2016, the net present value of future net revenues discounted at 10% (“PV10”) before taxes of our P+P reserves, inclusive of our internally estimated undeveloped land of $171 million and net of estimated net debt of $212 million equates to $8.34 per common share, an increase from $6.83 per common share at December 31, 2015.
- A total of 1,166 Viking horizontal wells are included in our PDP reserves.
- An additional 1,171 undeveloped locations have been booked leaving approximately 67% of our prospective locations as currently unbooked.
Fourth quarter 2016 production averaged approximately 20,400 boe/d (92% oil), bringing average 2016 annual production to 17,900 boe/d (92% oil) representing year over year production per debt adjusted share growth of 20%.
The $211.5 million of development capital resulted in 281 net wells drilled during 2016.
For 2017, quarter to date we have drilled approximately 48 net wells (51%) of the 93.5 net wells budgeted for the first quarter of 2017. 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 within the first quarter are expected to be $100 million.
Average on-stream costs quarter to date have averaged approximately 5 – 7% higher than the low’s witnessed in 2016. This cost inflation was anticipated within our budget and we remain on track to execute our 2017 budget at previously released levels for the year 2017 of $310 million.
Waterflood execution continues to be a priority in the first quarter with an estimated $20 million being spent on facilities. First waterflood reserves were recorded in 2016 from Sproule with approximately 700 mstb of oil being booked attributable to our ongoing waterfloods.
Extended Reach Horizontal (ERH) Update
We are strongly encouraged by the results of our initial phase of extended reach horizontal (“ERH”) wells drilled in the third and fourth quarters of 2016. To date, we have drilled over 41.5 net ERH wells across our asset base in Saskatchewan and an additional 17 net ERH wells in Alberta. Initial production rates of the ERH wells have exceeded management’s expectations, with the average ERH well seeing approximately two times the initial productivity of the comparable offsetting standard (approximately 600m) laterals. We look forward to providing further updates and quantifying the economic improvements we are achieving as we gain more performance history on the ERH wells.
Within the December 31, 2016 Sproule Report, 143 net ERH wells have been assigned undeveloped reserves, representing approximately 8% of Raging River’s current defined economic ERH inventory.
2016 Independent Reserves Evaluation:
The following summarizes certain information contained in the Sproule Report. The Sproule 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 2017.
Corporate Reserves Information:
|December 31, 2016|
|Proved developed producing||30,495||14,979||32,991||838,592||664||–|
|Proved developed non-producing||170||265||214||4,667||658||–|
|Probable developed producing||8,009||4,037||8,682||203,687||–||–|
|Probable developed non-producing||638||149||663||13,048||140||–|
|Total proven plus probable||88,055||35,606||93,989||1,962,477||813,040||1,171|
- “Oil” values include all light & heavy oil volumes, and natural gas liquids volumes.
- 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.
- Based on Sproule’s December 31, 2016 escalated price forecast.
- 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.
- 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.
- Totals may not add due to rounding.
- Pursuant to section 5.4.3 “Levels of Certainty for Reported Reserves” of 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
|December 31, 2016|
|BTAX NPV 5%||BTAX NPV 10%|
|P+P NPV (1,2)||2,548,372||10.64||1,962,477||8.20|
|Undeveloped acreage (3)||171,240||0.72||171,240||0.72|
|Net debt (4)||(212,000)||(0.89)||(212,000)||(0.89)|
|Proceeds from stock options (5)||75,522||0.32||75,522||0.32|
|Net Asset Value (fully-diluted)||2,583,134||10.79||1,997,239||8.34|
- Evaluated by Sproule as at December 31, 2016. Net present value of future net revenue does not represent fair market value of the reserves.
- 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, 2016.
- Internally evaluated with an average value of $400 per acre for 428,100 undeveloped net acres.
- Net debt as at December 31, 2016, including working capital deficit (unaudited).
- Fully-diluted shares at December 31, 2016 total: including outstanding common shares of 231.1 million and 8.3 million stock options that are in-the-money as at December 31, 2016.
- Per share figures based on fully-diluted shares outstanding as at December 31, 2016 – see note 5.
Future Development Costs
The following is a summary of the estimated FDC required to bring P+P undeveloped reserves on production.
|Future Development Capital Costs ($000s)|
|Total Proved +
|Total undiscounted FDC||761,739||813,040|
|Total discounted FDC at 10% per year||645,758||686,770|
|Average crude oil price WTI US$/bbl||43.32||48.80||93.00||97.98|
|Operating netback $/boe||29.76||35.51||64.51||60.07|
|Total Reserves mboe||32,991||24,530||19,103||12,004|
|Reserves additions mboe||15,013||10,433||11,024||9,599|
|Proved Plus Probable Producing|
|Total Reserves mboe||41,673||30,952||23,873||16,908|
|Reserves additions mboe||17,273||12,085||10,890||12,717|
|Total Reserves mboe||71,577||57,391||49,928||31,376|
|Reserves additions mboe||20,738||12,467||22,466||21,851|
|Change in FDC ($000)||84,939||(67,100)||262,071||298,429|
|Proven Plus Probable|
|Total Reserves mboe||93,989||76,361||63,565||42,729|
|Reserves additions mboe||24,180||17,800||24,750||27,619|
|Change in FDC ($000)||66,240||(43,900)||305,248||259,940|
- Financial and production information is per the Company’s 2016 preliminary unaudited financial statements and is therefore subject to audit.
- FD&A costs are used as a measure of capital efficiency. The calculation includes all capital costs 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: 2016 Total Proven = ($403,500,000+$84,939,000) / (71,577mboe-57,391 mboe +6,552 mboe) = $23.55 per boe.
- Recycle Ratio is calculated by dividing the operating netback per boe by the FD&A costs for that period. For example: 2016 Total Proven = ($29.76/$23.55) = 1.26. 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.
- 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: 2016 Total Proven = (71,577 mboe -57,391 mboe +6,552 mboe)/6,552 mboe = 317%.
- RLI is calculated by dividing the reserves in each category by the average annual production for that period. For example 2016 Total Proven = (71,577 mboe) / (17,900 boe*.366) = 11.0 years.
The following tables set forth the benchmark reference prices, as at December 31, 2016, reflected in the Sproule 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.
|SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1)|
|as of December 31, 2016|
|FORECAST PRICES AND COSTS|
|Thereafter Escalation rate of 2.0%|
- This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
- The exchange rate used to generate the benchmark reference prices in this table.
- As at December 31, 2016.
Our long term business model is robust, defined and is expected to generate meaningful free cashflow and earnings above growth capital. The Company has been built to withstand the volatility in commodity prices and provide meaningful per share growth to our shareholders. Per share growth has and will continue to be accomplished through excellence in execution, selective accretive acquisitions, maintenance of a pristine balance sheet and diligent development of new plays and play extensions.