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Raging River Exploration Inc. Initiates Process to Review Strategic Repositioning, Announces Fourth Quarter and Year End 2017 Operating and Financial Results and Provides Operations Update

CALGARY, Alberta, March 05, 2018 (GLOBE NEWSWIRE) -- Raging River Exploration Inc. (the “Company” or “Raging River”) (TSX:RRX) announces that Raging River’s Board of Directors (the "Board") has commenced a formal process to initiate a strategic repositioning of the Company (the “Repositioning Process”) in an effort to enhance shareholder value. Raging River believes that the current trading price of its common shares does not adequately reflect the underlying value of the Company. The purpose of the Repositioning Process is to evaluate a number of alternatives available to the Company concurrently.

In connection with the Repositioning Process, the Board intends to undertake a comprehensive review to identify and consider a broad range of alternatives to enhance shareholder value, including, but not limited to, a merger, corporate sale, corporate restructuring, the sale of select assets, the purchase of assets, or any combination of the potential alternatives. The Board has appointed an independent committee (the "Special Committee"), chaired by Raging River’s lead independent director, Kevin Olson, to facilitate and lead the review. GMP FirstEnergy has been engaged as the exclusive financial advisor to the Company and National Bank Financial Inc. as the advisor to the Special Committee in connection with this review.

Raging River continues to execute on its business plan and is in a strong financial position. Raging River does not intend to disclose developments with respect to the Repositioning Process unless the Board has approved a specific transaction, or otherwise determines that disclosure is necessary or appropriate.

2017 Financial and Operating Highlights

Selected financial and operational information is outlined below and should be read in conjunction with the audited financial statements, the related Management’s Discussion and Analysis (“MD&A”) and the Annual Information Form. These filings will be available at www.sedar.com and the Company’s website at www.rrexploration.com.

Three months ended
December 31,
Percent
Change
Year ended
December 31,
Percent
Change
2017 2016 2017 2016
Financial (thousands of dollars except share data)
Petroleum and natural gas revenue130,167 98,479 32 451,153 297,020 52
Funds flow from operations (1)83,867 64,561 30 281,991 188,188 50
Per share - basic 0.36 0.28 29 1.22 0.83 47
- diluted0.36 0.28 29 1.22 0.83 47
Net earnings 19,950 18,986 5 59,817 23,212 158
Per share - basic 0.09 0.08 13 0.26 0.10 160
- diluted0.09 0.08 13 0.26 0.10 160
Development capital expenditures74,554 76,658 (3) 372,073 211,556 76
Property and corporate acquisitions- 58,259 (100) - 144,647 (100)
Total capital expenditures74,554 134,917 (45) 372,073 356,203 4
Net debt(1)(3) 299,594 209,543 43
Shareholders’ equity 969,222 899,120 8
Weighted average shares (thousands)
Basic231,266 231,114 - 231,210 225,946 2
Diluted231,566 232,048 - 231,506 226,533 2
Shares outstanding, end of period (thousands)
Basic 231,271 231,142 -
Diluted 233,253 241,011 (3)
Operating (6:1 boe conversion)
Average daily production
Light crude oil and NGLs (bbls/d)20,891 17,058 22 19,863 15,589 27
Heavy crude oil (bbls/d)1,115 1,780 (37) 1,213 965 26
Natural gas (mcf/d)10,020 9,652 4 10,742 8,079 33
Barrels of oil equivalent (2) (boe/d)23,676 20,447 16 22,867 17,900 28
Netbacks ($/boe)
Operating
Oil and gas sales(3)59.76 52.35 14 54.05 45.34 19
Royalties(5.52) (4.94) 12 (5.08)(4.37) 16
Operating expenses(11.02) (10.79) 2 (10.96)(9.80) 12
Transportation expenses(1.39) (1.42) (2) (1.42)(1.41) 1
Field netback (1)41.83 35.20 19 36.59 29.76 23
Realized loss on risk management contracts(5)(0.70) (0.15) 367 (0.23)- 100
Operating netback (1)41.13 35.05 17 36.36 29.76 22
General and administrative expense(1.09) (1.00) 9 (1.06)(1.14) (7)
Financial charges(1.38) (0.82) 68 (1.17)(0.69) 70
Realized loss on risk management contracts(6)(0.06) - 100 (0.01)- 100
Asset retirement expenditures(0.10) (0.12) (17) (0.10)(0.07) 43
Current taxes recovery (expense)- 1.22 (100) (0.23)0.87 (126)
Funds flow netback(1)38.50 34.33 12 33.79 28.73 18
Net earnings 9.17 10.10 (9) 7.16 3.55 102
Wells drilled(4)
Gross60 121 (50) 370 303 22
Net49.9 106.1 (53) 329.8 273.5 21
Success96% 100% (4) 98%100% (2)

(1) See “Non-IFRS Measures.”
(2) See ‘“Barrels of Oil Equivalent.”
(3) Excludes unrealized risk management contracts.
(4) Excludes service wells.
(5) Includes realized losses on commodity contracts. Excludes realized losses on interest rate swap.
(6) Includes realizes losses on interest rate swap.

FOURTH QUARTER 2017 HIGHLIGHTS

  • Achieved a quarterly production record with average production of 23,676 boe/d (93% oil) representing an increase of 16% over the comparable period in 2016. This represents a 16% production per share increase from the fourth quarter of 2016.
  • Achieved funds flow from operations of $83.9 million ($0.36/share basic), a 39% increase quarter over quarter and a 30% increase from the fourth quarter of 2016.
  • The Company generated operating netbacks of $41.83/boe on an unhedged basis and funds flow netbacks of $38.50/boe.
  • Generated fourth quarter net earnings of $20 million or $9.17/boe.
  • Corporate royalties continued to be stable at 9.2% during the quarter.
  • The Company’s exploration and development expenditures for the quarter were $74.6 million. A total of 48.9 net Viking crude oil wells were drilled at a 96% success rate.
  • As previously reported, our initial Duvernay light oil discovery well was successfully drilled and completed in the fourth quarter.
  • Maintained a strong balance sheet with year-end net debt of $299.6 million representing 0.9 times net debt to fourth quarter annualized funds flow from operations.

YEAR ENDED DECEMBER 31, 2017

  • Production averaged 22,867 boe/d (92% oil), a 28% increase (25% production per share) from 2016 annual production of 17,900 boe/d.
  • Generated funds flow from operations of $282 million ($1.22/share basic) an increase of 50% from 2016.
  • Attained top decile general and administrative costs of $1.06/boe, a 7% decrease from 2016.
  • Executed a $372.1 million exploration and development program to drill a total of 328.8 net Viking crude oil wells and 1.0 net Duvernay well for a success rate of 98%. The capital expenditures consisted of $297.4 million of Viking development capital, $31.9 million of capital deployed into long term Viking waterflood initiatives as well as $42.8 million into early stage land capture and initial evaluation of an emerging Duvernay light oil play.
  • Proved plus probable reserves increased 14% to 106.7 mmboe (94% oil) and proved reserves increased 15% to 82 mmboe (94% oil).
  • Finding and development costs including the change in future development capital were:
    - $36.95 per boe on a proved developed producing basis resulting in a recycle ratio of 1.0 times.
    - $28.77/boe on a total proved basis resulting in a recycle ratio of 1.3 times.
    - $25.11/boe on a total proved plus probable basis resulting in a recycle ratio of 1.5 times.
  • Total net undeveloped land holdings increased 38% to 591,363 acres. The 38% increase in undeveloped land was primarily in the Duvernay shale basin where the Company now holds approximately 250,000 acres.
  • Increased our credit facilities to $500 million from $400 million in July 2017.

2018 OPERATIONS UPDATE

Viking Program

Our 113 net well Viking program for the first quarter will be finished with all rigs and fracture stimulation equipment released by mid-March.

Extended reach horizontal wells (“ERH”) continue to be a focus for the company with 71 net Viking ERH wells drilled this quarter (63% of the wells drilled). The Company has completed a thorough review of its historical ERH results. These results have continued to confirm that the ERH wells are providing a significant benefit to economics and recoverable reserves within Raging River's Viking drilling inventory. Based on the analysis of 27 one mile Raging River ERH wells and 89 three quarter mile Raging River ERH wells that have at least three months of production data, the ERH wells are outperforming the closest offset half mile well by a factor of 70%, for approximately 30% incremental capital cost.

Duvernay Program

As previously discussed in our February 21, 2018 press release, Raging River continues to prudently and methodically advance the evaluation of the emerging Duvernay light oil play in central Alberta. We continue to expand our prospective land base and currently Raging River controls 250,000 net acres (390 sections) within the Duvernay light oil fairway.

We have had continued geotechnical success throughout the first quarter. Our second well in the Ferrybank area (2-20 bottom hole) was successfully drilled to a total measured depth of 5,402m. As part of the drilling operations, we vertically drilled through the Duvernay formation and obtained open hole logs prior to plugging back, kicking-off and continuing to drill a 3,171m lateral section in the upper portion of the Duvernay formation. We plan to complete the 2-20 location after spring break up.

Our third Duvernay well in the Pembina (Pigeon Lake) area (14-36), has been successfully drilled and cased to a total measured depth of 5,058m with a 2,450m lateral section. As part of the drilling operations, we drilled and cored, and logged, the complete Duvernay section. Data from the open hole logs and preliminary core analysis has confirmed our geotechnical expectations of this area with estimated net pay in excess of 20m. Given the strong geotechnical result, the Company has elected to accelerate completion operations for this well into the first quarter. Fracture stimulation operations have recently commenced on this well and we anticipate starting flow back of this well later in March.

On February 28, 2018, we spud the third and final evaluation well of our first quarter 2018 delineation program in the Gilby area (Gilby 1-20). Similar to the Pigeon Lake 14-36 well, our plan is to drill a vertical pilot, core the Duvernay section and obtain a full suite of open hole logs, prior to plugging back and drilling a planned 2,200m lateral section in the Duvernay Formation. Completion operations are anticipated to commence late in the second quarter.

Raging River has been active surveying and acquiring surface leases in multiple areas, to continue to delineate and evaluate our expanding land base. Our current base plan contemplates six 100% working interest Duvernay evaluation wells in 2018. We may look to accelerate Duvernay activity in 2018, should commodity pricing and results continue to be supportive.

OUTLOOK

Based on strong performance in the Viking, we anticipate first quarter 2018 production to average 23,500 to 24,000 boe/d. With the acceleration of the 14-36 Duvernay completion, we anticipate first quarter 2018 capital spending to be approximately $110 million to $115 million.

Raging River is in a unique position to elicit change through the announced Repositioning Process in an effort to enhance shareholder value. We have a clean balance sheet with an estimated 2018 year-end net debt to trailing funds flow from operations of less than one times with a conservative credit facility of $500 million. Our exceptionally strong Viking drilling inventory with over 2,500 locations continues to allow us to meet and exceed forecast growth expectations with consistent success and an industry leading light oil netback. We continue to be excited by the prospects of our 390 section land position with positive early drilling results and increasing producer activity in the emerging Duvernay light oil play.

Raging River intends to continue to execute on its 2018 capital plan and its 2018 average production guidance of 24,500 boe/d remains intact. Raging River’s management team and Board are committed to acting in the best interests of the Company, and believe a Repositioning Process will ultimately benefit shareholders. The Repositioning Process has not been initiated as a result of receiving any offer or approach, or as a reaction to any operational results or deviations to the Company’s communicated or internal forecasts. The Company does not intend to periodically or otherwise, disclose developments with respect to the Repositioning Process unless the Board has approved a specific transaction or action plan, or otherwise determines that disclosure is necessary or appropriate. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction. The Company has not yet set a definitive schedule to complete its identification, examination and consideration of the strategic Repositioning Process.

Additional corporate information can be found in our corporate presentation on our website at www.rrexploration.com

FOR FURTHER INFORMATION PLEASE CONTACT:
RAGING RIVER EXPLORATION INC.RAGING RIVER EXPLORATION INC.
Mr. Neil Roszell, P. Eng.Mr. Bruce Beynon, P. Geol.
CEO and Executive ChairmanPresident
Tel: (403) 767-1250; Fax: (403) 387-2951Tel: (403) 767-1251; Fax: (403) 387-2951
RAGING RIVER EXPLORATION INC.
Mr. Jerry Sapieha, CA
Vice President, Finance and Chief Financial Officer
Tel: (403) 767-1265; Fax: (403) 387-2951

FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements, including, but not limited to, the following matters: the anticipated timing of completing the Company's first quarter Viking capital program; the expectation that ERH wells are providing a significant benefit to economics and recoverable reserves within Raging River's Viking drilling inventory; the expected timing of completing certain drilling, completion, testing and fracture stimulation of the Company's Duvernay wells; the anticipated targets of the Company's Duvernay wells; the intent to accelerate the pace of Duvernay activity should commodity prices and results continue to be supportive; the intent to continue to delineate and evaluate our expanding Duvernay land base; anticipated first quarter production; anticipated first quarter capital spending; the expectation that the Repositioning Process may elicit change and enhance shareholder value; forecast 2018 year-end net debt to trailing funds flow from operations; Raging River's estimated drilling inventory; the intent to continue to execute on the Company's 2018 capital plan; expectations with respect to the previously released 2018 production guidance; and expected details and possible benefits of the Repositioning Process. In addition, the use of any of the words “guidance”, “initial, “scheduled”, “can”, “will”, “prior to”, “estimate”, “anticipate”, “believe”, “potential”, “should”, “unaudited”, “forecast”, “future”, “continue”, “may”, “expect”, “project”, 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, receipt of required regulatory approval, the success of future drilling, development and waterflooding 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, prevailing equipment and services costs 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, 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 or capital expenditures; as 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, uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures and failure to achieve the anticipated benefits of the Repositioning Process or any transactions undertaken pursuant to the Repositioning Process. Refer to Raging River’s most recent Annual Information Form dated March 5, 2018, on SEDAR at www.sedar.com, and the risk factors contained therein.

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.

FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this press release, as defined by applicable securities legislation, has been approved by management of Raging River as of the date hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2018 has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results.

INITIAL RATES OF PRODUCTION AND PRELIMINARY GEOTECHNICAL INFORMATION: References in this press release to initial production rates, initial performance, recoveries and economics, net pay and other preliminary geotechnical information or anticipated results associated with the Company's ERH wells and Duvernay program are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. The Company cautions that such production rates should be considered to be preliminary.

NON-IFRS MEASURES: This document contains the terms "funds flow from operations", "net debt", "field netback", "operating netback" and "funds flow netback", which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculation of similar measures by other companies. Funds flow from operations, which most closely reconciles to the IFRS measure cash flow from operating activities, is presented before the change in non-cash operating working capital. Management uses funds flow from 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 "field netback", "operating netback" and "funds flow netback" are useful supplemental measures of firstly, the amount of revenues received after royalties and operating and transportation costs, secondly, the amount of revenues received after royalties, operating, transportation costs and realized gain (loss) on risk management contracts, and thirdly, the amount of revenues received after royalties, operating, transportation costs, realized gain (loss) on risk management contracts, general and administrative costs, financial charges, asset retirement obligations and current taxes. Additional information relating to certain of these non-IFRS measures, including the reconciliation between funds flow from operations and cash flow from operating activities, can be found in the MD&A.

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 finding and development costs and recycle ratio, 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 Company’s future performance. Finding and development costs are used as a measure of capital efficiency. The finding and development cost calculation includes all capital costs (exploration and development capital) for that period plus the change in future development capital for that period. This total capital including the change in the future development capital is then divided by the change in reserves for that period incorporating all revisions and production for that same period. The recycle ratio was calculated by dividing operating netback per boe by the finding and development costs for the year. For additional details on the calculation of these oil and gas metrics, see the Company's press release dated February 21, 2018 which is available on SEDAR at www.sedar.com and on the Company's website at www.rrexploration.com.

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 of the Company's Viking assets as prepared by Sproule as of December 31, 2017 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 2,500 drilling locations identified herein, 1,109 are proved locations, 51 are probable locations and 1,340 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.

Source: Raging River Exploration Inc.

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