CALGARY, ALBERTA–(Marketwired – Aug. 11, 2015) – Raging River Exploration Inc. (the “Company” or “Raging River”) (TSX:RRX) announces its operating and financial results for the three and six months ended June 30, 2015. Selected financial and operational information is outlined below and should be read in conjunction with the unaudited interim financial statements and the related management discussion and analysis (“MD&A”). These filings will be available at www.sedar.com and the Company’s website at www.rrexploration.com.
Financial and Operating Highlights
|Three months ended
|Six months ended
|2015||2014||Percent Change||2015||2014||Percent Change|
|Financial (thousands of dollars except share data)|
|Petroleum and natural gas revenue||73,465||88,931||(17)||128,471||169,638||(24)|
|Funds from operations (1)||49,535||56,283||(12)||83,014||106,095||(22)|
|Per share – basic||0.25||0.32||(22)||0.43||0.60||(28)|
|Per share – basic||0.06||0.17||(65)||0.07||0.31||(77)|
|Development capital expenditures||33,417||27,789||20||81,794||99,807||(18)|
|Property and corporate acquisitions||–||–||–||35,729||–||100|
|Total capital expenditures||33,417||27,789||20||117,523||99,807||18|
|Weighted average shares (thousands)|
|Shares outstanding, end of period (thousands)|
|Operating (6:1 boe conversion)|
|Average daily production|
|Crude oil and NGLs (bbls/d)||12,856||9,500||35||12,863||9,463||36|
|Natural gas (mcf/d)||2,947||2,765||7||2,795||2,518||11|
|Barrels of oil equivalent (2)(boe/d)||13,347||9,960||34||13,329||9,883||35|
|Oil and gas sales(3)||60.49||98.11||(38)||53.25||94.83||(44)|
|Realized gain on derivatives||0.37||(2.34)||(116)||0.97||(2.10)||(146)|
|Operating netback ($/boe)||42.92||72.16||(41)||36.48||69.53||(48)|
|General and administrative expense||(1.30)||(1.43)||(9)||(1.33)||(1.45)||(8)|
|Asset retirement expenditures||–||–||–||(0.01)||–||100|
|Funds flow netback||40.79||62.09||(34)||34.41||59.31||(42)|
|(1)See “Non-IFRS Measures”.|
|(2) Boe conversion ratio for natural gas of 1 Boe: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.|
|(3) Excludes unrealized risk management contracts.|
- Achieved another quarterly production record with average production of 13,347 boe/d (97% oil) representing an increase of 34% over the comparable period in 2014 and a 21% production per share increase from the comparable period of 2014.
- The Company’s capital expenditures were $33.4 million including $32.3 million on development activities in addition to $1.1 million on land. A total of 36 net Viking horizontal wells were drilled and a total of 48 net wells were completed and placed on stream inclusive of the 19.4 net wells drilled and not completed in the first quarter. Average on stream costs during the quarter were $700,000 per well representing a 22% cost reduction from the average costs seen in 2014.
- Generated top decile operating netbacks of $42.92/boe and funds flow netbacks of $40.79/boe in addition to positive earnings of $10.00/boe.
- Achieved our eighth consecutive quarterly decrease in operating and transportation costs to $12.08/boe, a 14% reduction from the comparable quarter of 2014 and a 5% reduction quarter over quarter.
- Continued our diligent cost control with top decile general and administrative costs of $1.30/boe, a reduction of 9% from the comparable period in 2014.
- Maintained balance sheet strength with second quarter exit net debt of $99.1 million representing 0.5 times debt to the second quarter annualized cash flow.
We are maintaining our capital budget of $235 million inclusive of $40 million of acquisitions, $20 million of waterflood capital in addition to $175 million of exploration and development expenditures. Annual average 2015 production guidance of 13,500 boe/d and exit production guidance of 15,000 boe/d remains unchanged. Based on current strip pricing of approximately US$46.50/bbl WTI for the remainder of 2015 we expect to exit the year with an exceptionally strong balance sheet with an estimated debt to trailing cashflow of approximately 0.75 times.
Focusing on the cost structure of the business has enabled us to materially decrease our sustaining capital requirements. Through increased efficiencies and reduced service provider costs, our average on-stream capital cost per well has been reduced from our historical average of $900-$925 thousand to the current level of $700-$750 thousand per well. To maintain a flat production profile in 2016 would require Raging River to spend approximately 85% of its cashflow at the current 2016 strip price of US$50/bbl WTI.
As the board of directors evaluates the five year business model for Raging River, it is evident that the Company continues to be in an enviable position. Our robust drilling inventory can continue to provide per share growth even under the current depressed commodity prices. Recognizing the strength of the Company, the board and management of Raging River continue to see that it is imperative that we continue to advance our initiatives of drilling inventory expansion and decline mitigation. Drilling inventory expansion will continue to come from our downspacing initiatives, land purchases in addition to new technology advancements. Decline mitigation will largely come from waterflood implementation in addition to a moderated growth rate.
Facilities construction and injector conversions for our previously mentioned waterflood expansions and new initiatives are in progress with first water injection occurring in July 2015 on three of our six project areas. Success with the waterflood expansions is anticipated to setup further full scale waterflood initiations in 2016 and beyond which will assist in mitigating longer term decline rates within our asset base.
Raging River continues to be encouraged by the results seen with our horizontal drilling in the Gleneath unit which has been under active waterflood since the mid 1960’s. The results seen within this waterflooded area provide significant support for our continued waterflood development plan. A summary of the well results are:
- The first two wells drilled by Raging River in the unit in late 2014 have been on production at average rates of 85 bbls/d for in excess of 9 months with no decline; both wells are top performers and on trend to produce 100,000 bbls of cumulative production per well.
- The average initial rate’s for four recent drills is similar to the first two quoted above at 75-100 bbls/d of oil which is approximately double the rate of our average wells in non waterflooded areas.
During the fourth quarter of 2014, a total of 11 wells were drilled in the Plato and Dodsland areas effectively increasing average well spacing from the defined convention of 16 wells per section to an average of 20-22 wells per section. These wells have been on production for in excess of 200 days with the infill wells seeing very similar results to the initial offsetting wells. The infill wells have shown very little interference with the existing producers. This continues to support the reasoning that well spacing will ultimately be much greater than 16 wells per section within the Saskatchewan Viking play.
New Land Acquisition
Subsequent to the end of the second quarter, Raging River acquired an additional 8.5 gross (4.5 net) sections of undeveloped land in our Beadle core operating area with in excess of 30 net high quality Viking drilling locations for consideration of $4.2 million.
Based on the current on-stream cost structure of approximately $725,000 per well and the success achieved with our initial downspaced wells, the Company’s current economic drilling locations are in excess of 2,400 net wells at US$50/bbl WTI. The current economic inventory represents sufficient wells to keep production flat for in excess of 15 years at US$50/bbl WTI.
Although commodity prices are currently weak, it is expected that over the longer term WTI will return to a more sustainable US$70/bbl WTI level. At this level, our economic drilling inventory increases to in excess of 3,500 locations.
Raging River has built a company around per share growth and prudent balance sheet management, positioning us exceptionally well through this recent volatility in commodity prices. As commodity prices strengthen and our asset base continues to mature we will evolve our business model to continue to achieve the best long term value proposition for all of our shareholders. The company will continue to deliver per share growth while maintaining balance sheet strength as we move towards a long term sustainable business model that, at that appropriate time, provide shareholders with sustainable income through dividends to complement our growth strategy.
Additional corporate information can be found in our corporate presentation on our website at www.rrexploration.com.
FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. More particularly, this press release contains statements concerning Raging River’s expectations regarding anticipated reduced service costs, plans and timing of execution of capital activities, expectations of the debt to trailing cash flow ratio, the expected percentage of our 2016 cash flow required to be spent to maintain our production, the expectations of the areas where waterflood capital will be deployed, the expectation that our drilling inventory can continue to provide per share value growth for our shareholders under even the most pessimistic of commodity price scenarios, our intent to continue to advance our initiatives of drilling inventory expansion and decline mitigation, the expectation that drilling inventory expansion will continue to come from our downspacing initiatives, land purchases in addition to new technology advancements, the expectation that decline mitigation will largely come from waterflood implementation in addition to a moderated growth rate, the expectation that the incremental capital will not provide increased production or reserves in 2015 but that a successful response to the water injection could have material positive impacts to the reserves and production declines in the areas under waterflood, the expected timing for spending the incremental waterflood capital and the expected response time, the expected characteristics of the waterflood project areas, that the expected knowledge gained from these projects is expected to provide meaningful value creation and the scope and scale to justify more widespread waterflood implementation in 2016 and 2017, expected results from the downspacing initiatives, expectations with respect to future commodity prices, expected future drilling locations, expected on stream costs for newly drilled wells, expected cumulative production from certain wells, our intent to evolve our business model to continue to achieve the best long term value proposition for all of our shareholders, and our intent to move towards a long term sustainable business model that provides shareholders with sustainable income through dividends to complement our growth strategy. 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, including the waterflood projects discussed herein, the downspacing initiatives discussed herein, the availability of capital, current legislation, 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, 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 and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Refer to Raging River’s most recent Annual Information Form dated March 9, 2015, 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.
NON-IFRS MEASURES: This document contains the terms “funds from operations” (or “cash flow”), “net debt”, “field netback”, “operating netback” and “funds flow 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 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 derivatives, and thirdly, the amount of revenues received after royalties, operating, transportation costs, realized gain (loss) on derivatives, general and administrative costs, financial charges and asset retirement obligations. Additional information relating to certain of these non-IFRS measures, including the reconciliation between funds 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.
INITIAL PRODUCTION RATES: Any references in this press release to initial production rates or flow back production results are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.
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 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 and/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 2,400 drilling locations (at an average 22 wells/section spacing) identified herein based on US$50/bbl WTI, 791 are proved locations, 50 are probable locations and 1,559 are unbooked locations. Of the 3,500 drilling locations (at an average 22 wells/section spacing) identified herein based on US$70/bbl WTI, 791 are proved locations, 50 are probable locations and 2,659 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. 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, additional reservoir information that is obtained 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.
Raging River Exploration Inc.
Mr. Neil Roszell
President and Chief Executive Officer
Raging River Exploration Inc.
Mr. Jerry Sapieha, CA
Vice President, Finance and Chief Financial Officer