CALGARY, ALBERTA–(Marketwired – Feb. 9, 2015) – Raging River Exploration Inc. (“Raging River” or the “Company“) (TSX:RRX) is pleased to report a year over year increase of 49% to proven plus probable reserves to 63.6 mmboe. Proven Developed Producing (“PDP”) Finding, Development and Acquisition (“FD&A”) costs were $25.18/boe resulting in a recycle ratio 2.5 times demonstrating the quality of the Company’s continuously expanding drilling inventory.
The Company is also pleased to announce a Viking consolidation transaction (the “Acquisition”) which will see the Company acquire 600 bbls/d of light oil and 30 net sections of land prospective for Viking light oil for total cash consideration of approximately $35.6 million subject to customary closing adjustments.
YEAR END 2014 RESERVES
The following summarizes certain information contained in the independent reserves report prepared by Sproule Associates Ltd. (“Sproule”) as of December 31, 2014. The report was prepared in accordance with definition, 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 March 9, 2015.
Reserve Report Highlights:
- Added 24.8 million boe of Proved Plus Probable (“P+P”) reserves (22.5 million boe Total Proven (“TP”)) in 2014 for a P+P reserve replacement ratio of 630% (570% TP).
- Increased P+P reserves by 49% to 63.6 mmboe (97% oil) and TP reserves by 59% to 49.9 mmboe (97% oil).
- Replaced 280% of 2014 production with 11 mmboe of PDP reserves added from our $276 million capital development program.
- FD&A costs including the change in Future Development Capital (“FDC”) of $305 million are $23.49 per boe on a P+P basis which results in a recycle ratio of 2.7 times.
- FD&A costs including the change FDC of $262 million are $23.96 per boe on a TP basis which results in a recycle ratio of 2.7 times.
- FD&A costs are $25.18 per boe on a PDP basis which results in a recycle ratio of 2.5 times.
- Reserves per fully diluted share increased by 48% to 324 boe per 1,000 shares from 218 boe per 1,000 shares.
- Net asset value per fully diluted share calculated on a present value before tax discounted at 10% (“BTPV10”) increased 45% to an estimated $9.29 per share at December 31, 2014 ($6.42 at December 31, 2013) inclusive of an internal land value of $146 million.
- TP reserves represent 79% of P+P reserves as at December 31, 2014.
- The reserves life index increased to 12.9 years using P+P reserves and based on updated increased average production guidance for 2015 of 13,500 boe/d.
- Raging River’s development drilling inventory has increased to 2,600+ risked locations as at January 1, 2015 of which approximately 66% are currently unbooked.
- As at December 31, 2014, the Company has a total of 613 net Viking wells included in proved developed producing reserves.
Corporate Reserves Information:
|December 31, 2014|
|Proved developed producing||18,318||4,710||19,103||674,518||–||–|
|Proved developed non-producing||50||31||56||1,057||916||–|
|Total proven plus probable||61,780||10,711||63,565||1,758,154||790,739||841|
- 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, 2014 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 abandonment costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
- Totals may not add due to rounding.
Net Asset Value
|December 31, 2014|
|NPV 5%||NPV 10%|
|Proved plus probable reserves NPV (1,2)||2,310,089||11.78||1,758,154||8.97|
|Undeveloped acreage (3)||146,000||0.74||146,000||0.74|
|Net debt (4)||(154,000)||(0.79)||(154,000)||(0.79)|
|Proceeds from stock options and warrants (5)||71,902||0.37||71,902||0.37|
|Net Asset Value (fully-diluted)||2,373,991||12.10||1,822,056||9.29|
- Evaluated by Sproule as at December 31, 2014. 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, 2014.
- Internally evaluated.
- Net debt as at December 31, 2014, including working capital deficit (unaudited).
- Fully-diluted shares at December 31, 2014 total: including outstanding common shares of 180.3 million and 15.7 million stock options and warrants.
- Per share figures based on fully-diluted shares outstanding.
Future Development Costs
The following is a summary of Sproule’s estimated future development capital required to bring proved and probable undeveloped reserves on production.
|Future Development Capital Costs (1)|
|(amounts in $000s)||Total Proved||Total Proved
|2017 and subsequent||275,983||302,588|
|Total undiscounted FDC||743,922||790,738|
|Total discounted FDC at 10% per year||644,080||683,013|
2014 FD&A Costs (1)
|2014||Three Year Average|
|(amounts in $000s except as noted)||Proved||Proved +
|FD&A costs, including FDC|
|Exploration and development capital expenditures(3)||271,300||271,300||494,837||494,837|
|Acquisitions, net of dispositions||4,700||4,700||210,928||210,928|
|Total change in FDC||262,071||305,248||690,198||731,623|
|Total FD&A capital, including change in FDC||538,071||581,248||1,395,963||1,437,388|
|Reserve additions, including revisions – Mboe||22,422||24,698||46,859||56,080|
|Acquisitions, net of dispositions – Mboe||44||52||6,032||8,758|
|FD&A costs, including FDC – $/boe||23.96||23.49||26.39||22.17|
- Financial information is per the Company’s 2014 preliminary unaudited financial statements and is therefore subject to audit.
- While NI 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented below.
- 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 reserves additions for that year.
- The acquisitions include the announced purchase price of corporate acquisitions rather than the amounts allocated to property, plant and equipment for accounting purposes. The capital expenditures also exclude capitalized administration costs.
The following tables set forth the benchmark reference prices, as at December 31, 2014, 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, 2014|
|FORECAST PRICES AND COSTS|
|Thereafter||Escalation rate of 1.5%|
- 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.
The Acquisition is consistent with Raging River’s continuing strategy to consolidate the Viking light oil fairway. The Acquisition includes wells and facilities throughout Raging River’s producing areas of Forgan, Plato and Dodsland. It also eliminates the promote and timing commitments associated with one of the farm-in agreements previously completed by Raging River and provides access to prospective lands that were previously excluded under the farm-in agreement.
The Acquisition includes 600 boe/d (100% light oil) of production and 30 net sections of highly prospective land targeting Viking oil. The drilling inventory associated with the Acquisition includes over 100 net drilling locations of which >50% are currently unbooked.
The total consideration for the Acquisition is approximately $35.6 million (subject to customary closing adjustments and regulatory approvals). The Acquisition is expected to close in mid-February with an effective date of January 1, 2015.
|Production(1):||600 boe/d (100% light oil)|
|Average decline rate:||30%/year|
|Proved plus Probable reserves(2):||2.8 MMboe (100% Viking light oil)|
|Land prospective for Viking oil:||19,200 net acres|
|Total Land:||59,000 net acres|
|Total risked drilling locations:||100 net horizontal wells (50% unbooked)|
|Operating netback (3)(4):||$30.00/boe|
- Based on forecasted average volumes for the month of January 2015. Gross production before the deduction of royalties and without including any royalty interest.
- Gross reserves before deduction of royalties and without including any royalty interest. Based on internally evaluated reserves estimates effective January 1, 2015 prepared by a qualified reserves evaluator in accordance with NI 51‐101 and the COGE Handbook.
- See Non-IFRS Measures.
- Based on Mixed Sweet Crude Price of CDN$ 60.00/bbl.
|Production(1):||$59,330 per producing boe|
|Proved plus Probable Reserves(2):||$12.70 per boe|
- Based on forecasted average volumes for the assets to be acquired pursuant to the Acquisition, for the month of January 2015.
- Reserves as disclosed above.
2015 INCREASED GUIDANCE
The Acquisition will increase the total 2015 budget from $175 million to approximately $210 million. The Acquisition is also anticipated to add approximately 500 bbls/d of production for the last three quarters of the year resulting in an increase to our average guidance from 13,100 boe/d to 13,500 boe/d and an increase in our exit production guidance from 14,500 boe/d to 15,000 boe/d.
Raging River’s upwardly revised guidance for 2015 is as follows:
|Average (boe/d) (97% Oil)||13,500|
|Exit barrels of oil equivalent (boe/d) (97% Oil)||15,000|
|Crude oil – WTI ($US/bbl)||54.00|
|Exchange rate ($US/$Cdn)||0.80|
|Natural gas – AECO ($/GJ)||2.61|
|Differential – WTI to Canadian Light ($Cdn/bbl)||8.00|
|Operating cashflow ($000)||167,000|
|Funds flow from operations ($000)||158,000|
|2015 exit net debt ($000)||125,000|
|Net debt to funds from operations||0.8:1|
|Oil and gas sales||53.10|
|Operating & Transport Expense||13.50|
|Funds from operations||32.00|
|Drilling, completion & equipping ($000)||168,000|
|Land, seismic and maintenance ($000)||3,500|
|Facilities & waterflood ($000)||3,500|
Raging River is in the midst of another active quarter in which we anticipate drilling 50 net horizontal wells. We have drilled 43 gross (39 net) wells at a 100% success rate this quarter and anticipate being complete on our first quarter program within the next 2-3 weeks. The first six wells have been drilled on the previously announced west Dodsland farm-in with early encouraging results. In the quarter to date, Raging River has successfully tested 8 previously undrilled net sections, five of which were on the Dodsland farm-in lands.
Raging River continues to focus on operational and execution excellence while diligently pursuing accretive acquisitions. The recently completed financing and Acquisition emphasizes your team’s dedication to continuing to create shareholder value throughout all commodity environments.
Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, that the conditions for the Acquisition will not be satisfied, that the Acquisition will not close when expected, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects, capital expenditures, acquisitions or other corporate transactions; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. In addition, Raging River’s expectations and plans for its 2015 capital program and its 2015 guidance may change as circumstances change and as different opportunities arise, such as acquisition opportunities, and as the Company continues to evaluate its drilling results and opportunities. To the extent any guidance or forward looking statements herein constitute a financial outlook, they are included herein to provide readers with an understanding of management’s plans and assumptions for budgeting purposes and readers are cautioned that the information may not be appropriate for other purposes. Additional information on these and other factors that could affect Raging River’s operations and financial results are included in the Company’s Annual Information Form and other reports on file with Canadian securities regulatory authorities, which may be accessed through the SEDAR website (www.sedar.com).
The forward-looking statements contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
BARRELS OF OIL EQUIVALENT: The term “boe” or barrels of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (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. Additionally, 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 ratio of 6:1 may be misleading as an indication of value.
RECYCLE RATIO: The recycle ratio was calculated by dividing operating netback by the FD&A costs for the year. Operating netback is defined as revenues received after royalties and operating and transportation costs.
FINDING, DEVELOPMENT AND ACQUISITION COSTS: Finding and development costs including acquisitions and dispositions have been presented herein. While NI 51-101 requires that the effects of acquisitions and dispositions be excluded, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. The Company’s finding and development costs, excluding the effects of acquisitions and dispositions, for 2014 were $23.80/boe on a proved basis and $23.34/boe on a proved plus probable basis. The Company’s finding and development costs, excluding the effects of acquisitions and dispositions, for 2013 were $25.62/boe on a proved basis and $18.87/boe on a proved plus probable basis. The Company’s average finding and development costs for the last three years, excluding the effects of acquisitions and dispositions, were $25.29/boe on a proved basis and $21.87/boe on a proved plus probable basis. 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 reserves additions for that year.
DRILLING LOCATIONS: This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked 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 Sproule as of December 31, 2014 and account for drilling locations that have associated proved or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 2,600 drilling locations identified herein, 791 are proved locations, 50 are probable locations and 1,759+ are unbooked locations. Unbooked locations have specifically been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves data on prospective acreage and geologic formations. The drilling locations on which we 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.
NON-IFRS MEASURES: This document contains the terms “funds from operations”, “net debt” and “operating netback”, which do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable with the calculation of similar measures by other companies. Management uses funds generated by operations to analyze operating performance and leverage. Management believes “net debt” is a useful supplemental measure of the total amount of current and long-term debt of the Company. Mark-to-market risk management contracts are excluded from the net debt calculation. Management believes “operating netback” is a useful supplemental measures of the amount of revenues received after royalties and operating and transportation costs and secondly, the amount of revenues received after the royalties, operating, transportation costs, general and administrative costs, financial charges and asset retirement obligations. Additional information relating to these non-IFRS measures, including the reconciliation between funds from operations and cash flow from operating activities, can be found in the Company’s most recent management’s discussion and analysis MD&A, which may be accessed through the SEDAR website (www.sedar.com).
Raging River Exploration Inc.
Mr. Neil Roszell
President and CEO
(403) 387-2951 (FAX)
Raging River Exploration Inc.
Mr. Jerry Sapieha, CA
Vice President, Finance and CFO
(403) 387-2951 (FAX)