CST: 27/09/2016 17:19:42   

Raging River Exploration Inc. Announces 2015 Year End Reserves and Updated 2016 Guidance

236 Days ago

CALGARY, ALBERTA--(Marketwired - Feb 3, 2016) - 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, 2015. Sproule evaluated 100% of the Company's reserves in 2015 as they have done since the Company's inception in 2012.

During 2015, the Company invested $340 million (unaudited) consisting of $169 million of acquisition capital and $171 million of development capital into the expansion and development of the Viking play. This invested capital resulted in average annual production of 13,715 boe/d representing year over year production per share growth of 20%. Exit production of 17,000 boe/d was achieved which represents a 17% per share increase over the comparable 2014 exit rate.

A recycle ratio of 2.14 was achieved in 2015 despite average commodity prices being 40% below those recorded in 2014. Proved plus Probable ("P+P") Finding Development and Acquisition ("FD&A") costs including changes in Future Development Capital ("FDC") were $16.63/boe in 2015.

Historical Highlights

  • Since our inception in 2012 Raging River has invested a total of $1.05 billion expanding and developing the Viking play. During this time Raging River has generated approximately $540 million of funds flow from operations and, on a P+P basis achieved a cumulative reserves per share growth of 271%.
  • During that time producing reserves of 39.7 million boe were added at an FD&A cost of $26.33 per boe. Over that same period our weighted average operating netback has been $50.73/boe resulting in a full cycle cumulative recycle ratio of 1.93.
  • Raging River has significantly expanded its drilling inventory during this time. The Company has in excess of 3,800 remaining drilling locations of which approximately 74% are not currently booked.
  • At inception, Raging River had approximately 1,000 bbls/d of Viking oil production and 85 net sections of prospective acreage with 300 potential drilling locations. After four years of focusing on this singular play, we have drilled or acquired 911 net horizontal Viking oil wells and expanded our land base to include approximately 3,800 remaining drilling locations on 390 net prospective sections of land.

YEAR END 2015 RESERVES

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 2016.

Reserve Report Highlights:

  • Added 17.8 million boe of P+P reserves (12.5 million boe Total Proven ("TP")) in 2015 for a P+P reserve replacement ratio of 356% (249% TP).
  • Increased P+P reserves by 20% to 76.4 mmboe (90% oil) and TP reserves by 15% to 57.4 mmboe (92% oil).
  • Increased Proven Developed Producing ("PDP") reserves by 5.4 mmboe which replaced production by 208%.
  • FD&A costs including the change in FDC are $16.63 per boe on a P+P basis which results in a recycle ratio of 2.14 times
  • FD&A costs including the change in FDC are $21.89 per boe on a TP basis which results in a recycle ratio of 1.62 times
  • FD&A costs are $32.59 per boe on a PDP basis which results in a recycle ratio of 1.09 times
  • TP reserves (57.4 mmboe) represents 75% of P+P reserves as at December 31, 2015.
  • The reserves life index ("RLI") is 12.3 years using P+P reserves and based on exit 2015 production of 17,000 boe/d.
  • As at December 31, 2015, the Company has a total of 911 net Viking horizontal oil wells included in PDP reserves.

Corporate Reserves Information:

December 31, 2015
Reserves Category
Oil(1)
Mbbl

Gas
MMcf
Oil
Equivalent
MBOE
BTAX PV
10%
($000's)
Future Development
Capital
($000's)
Net
Undeveloped
Wells
Booked
Proved developed producing 22,432 12,592 24,530 603,331 - -
Proved developed non-producing 24 24 590 238 -
Proven undeveloped 30,480 14,138 32,836 372,445 676,583 892
Total proven 52,936 26,730 57,391 976,366 676,821 892
Probable developed producing 5,876 3,275 6,421 146,287 - -
Probable developed non-producing 28 - 28 885 238 -
Probable undeveloped 11,007 9,084 12,522 343,343 69,773 87
Total probable 16,911 12,359 18,971 490,515 70,011 87
Total proven plus probable 69,847 39,089 76,362 1,466,881 746,832 979

Notes:

  1. "Oil" values include all light & heavy oil volumes, and 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, 2015 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 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 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, 2015
NPV 5% NPV 10%
($000's) $/shares(6) ($000's) $/shares(6)
P+P NPV (1,2) 1,940,250 8.97 1,466,881 6.78
Undeveloped acreage (3) 135,000 0.63 135,000 0.63
Net debt (4) (140,000) (0.65) (140,000) (0.65)
Proceeds from stock options (5) 15,600 0.07 15,600 0.07
Net Asset Value (fully-diluted) 1,950,850 9.02 1,477,481 6.83

Notes:

  1. Evaluated by Sproule as at December 31, 2015. 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, 2015.
  3. Internally evaluated with an average value of $480 per acre for 280,000 undeveloped acres.
  4. Net debt as at December 31, 2015, including working capital deficit (unaudited).
  5. Fully-diluted shares at December 31, 2015 total: including outstanding common shares of 213.4 million and 2.9 million stock options that are in-the-money as at December 31, 2015.
  6. Per share figures based on fully-diluted shares outstanding as at December 31, 2015 - 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
(amounts in $000s) Total Proved Total Proved +
Probable
2016 208,076 215,951
2017 191,020 220,691
2018 193,200 217,390
2019 84,525 92,800
Total undiscounted FDC 676,821 746,832
Total discounted FDC at 10% per year 574,758 632,709

Performance Measures (1)

2015 2014 2013 2012
Average crude oil price WTI US$/bbl 48.80 93.00 97.98 94.19
Capital ($000) 339,950 278,594 272,495 154,032
Production boe/d 13,715 10,755 5,665 2,277
Operating netback $/boe 35.52 64.51 60.07 54.76
Proved Producing
Total Reserves mboe 24,530 19,103 12,004 4,473
Reserves additions mboe 10,431 11,024 9,599 3,054
FD&A $/boe(2) 32.59 25.27 28.39 50.44
Recycle Ratio(3) 1.09 2.55 2.12 1.09
Reserves Replacement(4) 208% 281% 464% 461%
RLI (years)(5) 4.9 4.9 5.8 6.8
2015 2014 2013 2012
Proved Plus Probable Producing
Total Reserves mboe 30,952 23,873 16,908 6,258
Reserves additions mboe 12,083 10,890 12,717 4,006
FD&A $/boe(2) 28.13 25.58 21.43 38.45
Recycle Ratio(3) 1.26 2.52 2.80 1.42
Reserves Replacement(4) 241% 277% 615% 605%
RLI (years)(5) 6.2 6.1 8.2 9.4
Total Proven
Total Reserves mboe 57,391 49,928 31,376 11,544
Reserves additions mboe 12,467 22,466 21,851 8,451
Change in FDC ($000) (67,100) 262,071 298,429 129,698
FD&A $/boe(2) 21.89 24.07 26.13 33.57
Recycle Ratio(3) 1.62 2.68 2.30 1.63
Reserves Replacement(4) 249% 572% 1057% 1275%
RLI (years)(5) 11.5 12.7 15.2 17.4
Proven Plus Probable
Total Reserves mboe 76,361 63,565 42,729 17,164
Reserves additions mboe 17,800 24,750 27,619 12,380
Change in FDC ($000) (43,900) 305,248 259,940 166,435
FD&A $/boe(2) 16.63 23.59 19.28 25.89
Recycle Ratio(3) 2.14 2.73 3.12 2.12
Reserves Replacement(4) 356% 630% 1336% 1868%
RLI (years)(5) 15.3 16.2 20.7 25.9

Notes:

  1. Financial and production information is per the Company's 2015 preliminary unaudited financial statements and is therefore subject to audit.
  2. 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: 2015 Total Proven = (339,950-67,100) / (57,391-49,928+5,004) = $21.89 per boe.
  3. Recycle Ratio is calculated by dividing the operating netback per boe by the FD&A costs for that period. For example: 2015 Total Proven = (35.52/21.89) = 1.62. 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: 2015 Total Proven = (57,391-49,928+5,004)/5,004 = 249%.
  5. RLI is calculated by dividing the reserves in each category by the average annual production for that period. For example 2015 Total Proven = (57,391) / (13,709*.365) = 11.5 years.

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2015, 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, 2015
FORECAST PRICES AND COSTS
Year WTI
Cushing
Oklahoma
($US/Bbl)
Canadian
Light Sweet
40
° API
($Cdn/Bbl)
Cromer
LSB 35
° API
($Cdn/Bbl)
Natural Gas AECO-C Spot
($Cdn/
MMBtu)
NGLs
Edmonton Pentanes Plus
($Cdn/Bbl)
NGLs Edmonton Butanes
($Cdn/Bbl)
Operating Cost Inflation Rates
%/Year
Capital Cost Inflation Rates
%/Year
Exchange Rate (2)
($Cdn/$US)
Forecast(3)
2016 45.00 55.20 54.20 2.25 59.10 39.09 0.0 0.0 0.750
2017 60.00 69.00 68.00 2.95 73.88 51.43 0.0 4.0 0.800
2018 70.00 78.43 77.43 3.42 83.98 58.46 1.5 4.0 0.830
2019 80.00 89.41 88.41 3.91 95.73 66.64 1.5 4.0 0.850
2020 81.20 91.71 90.71 4.20 98.19 68.35 1.5 1.5 0.850
2021 82.42 93.08 92.08 4.28 99.66 69.38 1.5 1.5 0.850
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, 2015.

UPDATED 2016 GUIDANCE

The Company has reduced its commodity price expectations for 2016. We are now budgeting a commodity price forecast of US$32.50/bbl WTI for the first half of 2016 and US$35/bbl WTI for the second half of 2016. AECO natural gas prices are forecast to be $2.35/mcf for all of 2016. As a result of the commodity price collapse that has been witnessed in 2016, we are reducing our capital budget from $190 million to a range of $150-$160 million.

During the first half of 2016, capital expenditures are anticipated to be approximately $50-$60 million with the lower end of the range equating to budgeted funds flow from operations at US$30/bbl WTI. Total 2016 funds flow from operations are forecast to be approximately $121 million.

The revised 2016 capital program of $150-$160 million consists of 180-185 net wells which is expected to generate 2016 average daily production of 16,500 boe/d (91% oil), a 20% (13.5% per share) increase over 2015 production. The revised budget contemplates 2016 exit production of 17,000 boe/d.

Raging River expects to maintain its strong balance sheet with exit 2016 net debt now estimated at $170 million (equating to a trailing net debt to funds flow ratio of approximately 1.4:1).

Raging River continues its focus on enhancing its prospective acreage through swaps, crown land sales, freehold leasing opportunities and purchases of additional acreage and production in our core area. The weakness in commodity prices continues to present unique opportunities to continue to consolidate quality assets. In 2016, we have already expanded our net prospective Viking acreage by 11 sections.

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 details of Raging River's 2016 planned capital program; expectations of commodity prices; guidance relating to 2016 including expectations as to average production, funds flow from operations, 2016 exit net debt and 2016 exit net debt to funds flow from operations; details of our drilling inventory; the expected continued focus on expanding the Company's prospective acreage in the Viking area; and the expectation that continued weakness in commodity prices will continue to present opportunities to consolidate land.. 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 the success of optimization and efficiency improvement projects, the availability of capital, current legislation, pipeline, transportation and processing 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 expectations as to 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, 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 2016 capital program and its 2016 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.

OIL AND GAS METRICS: This press release contains a number of oil and gas metrics, including FD&A, recycle ratio, reserves replacement, and reserves life index or RLI, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

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, 2015 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 3,800 drilling locations identified herein, 892 are proved locations, 87 are probable locations and 2,821+ 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, and 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. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

NON-IFRS MEASURES: This document contains the terms "funds flow from operations", "net debt", "operating netback", and "funds flow netback" that 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 flow from operations, which is presented before the change in non-cash operating working capital, 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 measure of the amount of revenues received after royalties and operating and transportation costs and "funds flow netback" is a useful supplemental measure of 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 flow from operations and cash flow from operating activities, can be found in the Company's most recent management's discussion and analysis, which may be accessed through the SEDAR website (www.sedar.com).

Raging River Exploration Inc.
Mr. Neil Roszell
President and CEO
Tel: (403)767-1250
Fax: (403)387-2951
Raging River Exploration Inc.
Mr. Jerry Sapieha, CA
Vice President, Finance and CFO
Tel: (403)767-1265
Fax: (403)387-2951