CALGARY, ALBERTA -- (Marketwired) -- 02/09/15 -- 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
Future Net
Reserves Oil BTAX PV Development Undeveloped
Category Oil Gas Equivalent 10% Capital Wells
Mbbl MMcf MBOE ($000's) ($000's) Booked
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Proved
developed
producing 18,318 4,710 19,103 674,518 - -
Proved
developed non-
producing 50 31 56 1,057 916 -
Proven
undeveloped 30,156 3,679 30,769 570,804 743,006 791
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Total proven 48,524 8,420 49,928 1,246,379 743,922 791
Probable 13,255 2,291 13,637 511,775 46,817 50
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Total proven
plus probable 61,780 10,711 63,565 1,758,154 790,739 841
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Notes:
1. 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.
2. Based on Sproule's December 31, 2014 escalated price forecast.
3. 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.
4. 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.
5. Totals may not add due to rounding.
Net Asset Value
December 31, 2014
NPV 5% NPV 10%
($000's) $/shares(6) ($000's) $/shares(6)
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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
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Net Asset Value (fully-
diluted) 2,373,991 12.10 1,822,056 9.29
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Notes:
1. Evaluated by Sproule as at December 31, 2014. 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, 2014.
3. Internally evaluated.
4. Net debt as at December 31, 2014, including working capital deficit
(unaudited).
5. Fully-diluted shares at December 31, 2014 total: including outstanding
common shares of 180.3 million and 15.7 million stock options and
warrants.
6. 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)
Total Proved
(amounts in $000s) Total Proved + Probable
----------------------------
2015 193,641 193,641
2016 274,298 294,509
2017 and subsequent 275,983 302,588
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Total undiscounted FDC 743,922 790,738
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Total discounted FDC at 10% per year 644,080 683,013
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2014 FD&A Costs (1)
2014 Three Year Average
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----------------------------------------
Proved + Proved +
(amounts in $000s except as noted) Proved Probable Proved Probable
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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
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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
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FD&A costs, including FDC - $/boe 23.96 23.49 26.39 22.17
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Notes:
1. Financial information is per the Company's 2014 preliminary unaudited
financial statements and is therefore subject to audit.
2. While NI 51-101 requires that the effects of acquisitions and
dispositions be excluded from the calculation of finding and development
costs, FD&A costs have been presented because acquisitions and
dispositions can have a significant impact on the Company's ongoing
reserve replacement costs and excluding these amounts could result in an
inaccurate portrayal of the Company's cost structure. Finding and
development costs both including and excluding acquisitions and
dispositions have been presented below.
3. The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
4. The acquisitions include the announced purchase price of corporate
acquisitions rather than the amounts allocated to property, plant and
equipment for accounting purposes. The capital expenditures also exclude
capitalized administration costs.
Pricing Assumptions
The following tables set forth the benchmark reference prices, as at December 31, 2014, reflected in the Sproule Report. These price assumptions were provided to Raging River by Sproule and were Sproule's then current forecast at the date of the Sproule Report.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1)
as of December 31, 2014
FORECAST PRICES AND COSTS
Canadian Natural
Light Cromer Gas
WTI Sweet LSB AECO-C
Cushing 40 degrees 35 degrees Spot
Oklahoma API API ($Cdn/
Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) MMBtu)
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Forecast(3)
2015 65.00 70.35 69.85 3.32
2016 80.00 87.36 86.86 3.71
2017 90.00 98.28 97.78 3.90
2018 91.35 99.75 99.25 4.47
2019 92.72 101.25 100.75 5.05
2020 94.11 103.85 103.35 5.13
NGLs
Edmonton NGLs
Pentanes Edmonton
Plus Butanes Inflation Exchange
($Cdn/ ($Cdn/ Rates Rate(2)
Year Bbl) Bbl) %/Year ($Cdn/$US)
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Forecast(3)
2015 78.60 50.34 1.5 0.85
2016 97.60 62.51 1.5 0.87
2017 109.80 70.32 1.5 0.87
2018 111.44 71.37 1.5 0.87
2019 113.12 72.44 1.5 0.87
2020 116.02 74.31 1.5 0.87
Thereafter Escalation rate of 1.5%
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.
ACQUISITION
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 greater than 50% are currently unbooked.
Acquisition summary:
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): $30.00/boe
1. Based on forecasted average volumes for the month of January 2015. Gross
production before the deduction of royalties and without including any
royalty interest.
2. Gross reserves before deduction of royalties and without including any
royalty interest. Based on internally evaluated reserves estimates
effective January 1, 2015 prepared by a qualified reserves evaluator in
accordance with NI 51-101 and the COGE Handbook.
3. See Non-IFRS Measures.
4. Based on Mixed Sweet Crude Price of CDN$ 60.00/bbl.
Acquisition metrics:
Production(1): $59,330 per producing boe
Proved plus Probable Reserves(2): $12.70 per boe
1. Based on forecasted average volumes for the assets to be acquired
pursuant to the Acquisition, for the month of January 2015.
2. Reserves as disclosed above.
2015 INCREASED GUIDANCE
The Acquisition will increase the total 2015 budget from $175 million to approximately $210 million. The Acquisition is also anticipated to add approximately 500 bbls/d of production for the last three quarters of the year resulting in an increase to our average guidance from 13,100 boe/d to 13,500 boe/d and an increase in our exit production guidance from 14,500 boe/d to 15,000 boe/d.
Raging River's upwardly revised guidance for 2015 is as follows:
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Revised
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Production
Average (boe/d) (97% Oil) 13,500
Exit barrels of oil equivalent (boe/d) (97% Oil) 15,000
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Pricing
Crude oil - WTI ($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
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Financial
Operating cashflow ($000) 167,000
Funds flow from operations ($000) 158,000
2015 exit net debt ($000) 125,000
Net debt to funds from operations 0.8:1
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Netbacks ($/boe)
Oil and gas sales 53.10
Royalties 6.00
Operating & Transport Expense 13.50
Operating netback 33.75
Hedging gains 0.50
G&A 1.30
Financial charges 1.00
Cash taxes -
Funds from operations 32.00
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Capital expenditures
Drilling, completion & equipping ($000) 168,000
Land, seismic and maintenance ($000) 3,500
Facilities & waterflood ($000) 3,500
Acquisitions ($000) 35,600
Total ($000) 210,600
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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.
Additional corporate information can be found on our website at www.rrexploration.com or on www.sedar.com.
FORWARD-LOOKING STATEMENTS: This press release contains forward-looking statements. More particularly, this press release contains statements concerning the anticipated terms and timing for closing the Acquisition, our continuing strategy to continue to consolidate the Viking light oil fairway, details of Raging River's 2015 planned capital program including Raging River's drilling and completion plans and the expected timing and locations thereof, average production guidance for 2015, anticipated exit production for 2015, expected net debt to cash flow ratio, expected cash flow sensitivities to changes in oil prices, expectations of changes in commodity prices, guidance relating to 2015 including expectations as to production, cashflow, general and administrative expenses, hedging gains, financial charges, cash taxes, royalties, operating expenses, transportation expenses, funds from operations, netbacks, net debt and debt to funds from operations, details of our drilling inventory, intention to continue to focus on operational and execution excellence while diligently pursuing accretive acquisitions and intention to continue to create shareholder value throughout all commodity environments. In addition, the use of any of the words "guidance", "initial, "scheduled", "can", "will", "prior to", "estimate", "anticipate", "believe", "should", "unaudited", "forecast", "future", "continue", "may", "expect", and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning including but not limited to expectations and assumptions that the Acquisition will close on the terms and at the time expected, all regulatory approvals and other conditions will be received or satisfied for closing the Acquisition, the success of optimization and efficiency improvement projects, the availability of capital, current legislation, pipeline capacity, receipt of required regulatory approval, the success of future drilling and development activities, the performance of existing wells, the performance of new wells, Raging River's growth strategy, general economic conditions, availability of required equipment and services and the costs of obtaining such equipment and services, and prevailing commodity prices. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct.
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).
Contacts:
Raging River Exploration Inc.
Mr. Neil Roszell
President and CEO
(403) 767-1250
(403) 387-2951 (FAX)
Raging River Exploration Inc.
Mr. Jerry Sapieha, CA
Vice President, Finance and CFO
(403) 767-1265
(403) 387-2951 (FAX)
www.rrexploration.com
